In order for the pipeline industry to usher in the next-level fracture mechanics engineering analysis, reasonable and prudent fracture toughness characterizations are needed to improve burst pressure predictions and fatigue crack growth analysis of pipelines with planar cracks. Converting Charpy V-Notch (CVN) value to fracture toughness via different empirical correlation models derived throughout the years, while laudable, have inherent shortcomings. The main issues being that the Charpy toughness test is not a fracture mechanics-based measurement and the transferability of sub-scale fracture toughness testing is often not completely understood nor is correctly applied. This paper expands on these shortcomings and presents solutions which are supported by fracture toughness data obtained from the pipe boy and seam weld of API 5L line pipe steels. In this manner, best available toughness derivations for mean toughness in base metal and long seam welds are presented. Suggestions for standard fracture mechanics sub-scale coupon testing, such as ASTM E1820, on pipeline steel samples are delineated with rationale for each test type. The transferability of fracture toughness from sub-scale coupon testing results to that exhibits in full-scale pipe failure are demonstrated in the paper. This fracture toughness test database and other similar data sets can be combined and serve as the basis for establishing an industry wide Pipeline Material Database which would mirror established material databases in the aerospace industry such as NASGRO and AFMAT. It is envisioned that a centralized and validated Pipeline Material Database will be expanded to include fatigue crack growth rate data and other pipeline material characterization data sets. These data will support minimizing material assumptions and increase the accuracy of structural integrity predictions to improve the overall pipeline performance. This combined database would be accessible to engineers, analysts, and researchers and updated at regular intervals as more data becomes available.

A safety advisory (2010-01), issued by the National Energy Board (NEB) in June 2010, referenced two incidents which were a result of a fatigue crack failure that occurred within shallow dents [1]. The dents in both instances were less than 6% (of the OD). Currently, there is no consensus on how shallow dents or shallow dents with stress concentrators, as called by the ILI tool, are assessed and acted upon. BMT Canada Ltd. (BMT) was contracted by the Canadian Energy Pipeline Association (CEPA) to develop a definition for shallow dents, and two levels of screening method for the integrity assessment of shallow restrained dents and unrestrained dents. These two levels are known as CEPA Level 0 and CEPA Level 0.5 dent integrity assessment techniques that may be applied without finite element modelling or detailed calculations. The BMT dent assessment finite element (FE) modeling method was used to develop an extensive database of dents for different pipe geometries (OD/t), indenter shapes, pipe grades, and indentation depths. The results of the FE modelling were used to develop trends for the stress magnification factors (K M ) across the range of pipes and dents modelled. These trends are used as the basis for the Level 0 and Level 0.5 dent screening and assessment approaches that can be used for both unrestrained dents and shallow restrained dents. The results show that for low OD/t pipe geometry and/or low spectrum severity indicator (SSI) [2] dent fatigue life may not pose an integrity threat. These dent screening approached have been adopted in the API Recommended Practice 1183 Dent Assessment and Management, that is currently under development.

While the general fracture mechanics principles and methodologies for calculating fatigue lives are well documented and validated, their application in the prediction of pipeline system fatigue lives differed from field experience. The source and magnitude of the conservatism inherent in the calculated fatigue life estimates are an important element when establishing integrity management programs. Of particular interest are the fatigue life estimates used in integrity management programs for electric resistance welded (ERW) pipeline systems that may have pipe seam anomalies oriented along the pipe axis. BMT Canada Ltd (BMT) was contracted by Pipeline Research Council International (PRCI) to develop a pipeline material fatigue crack growth database and conduct full scale cyclic pressure fatigue tests to develop improved crack growth rate parameters. A pipeline material fatigue crack growth database was developed using 185 fatigue crack growth rate tests on 45 pipeline materials ranging in grade from X46 to X70 and in vintage from 1937 to 2014. The database included fatigue crack growth rate tests on 18 pipe body base materials (BM) and 27 ERW weld seam materials at two different, stress ratios (R), of R-ratio = 0.1 and R-ratio = 0.6. The sampled crack growth rates observed in the pipeline steels, tested in the project were 2 to 3 times lower than the crack growth rates recommended in BS 7910. This paper presents the proposed power (Paris) law fatigue crack growth equation parameters, C and m, developed in the study. Two full-scale cyclic pressure tests were carried out to validate the use of recommended crack growth rate parameters. Axial flaws were machined in the pipe body and weld center line (WCL). Fifty-one (51) flaws of different lengths and depths were machined. The crack growth rates were monitored during the cyclic pressure tests by recording crack mouth opening displacement (CMOD). The calibration curves for correlating CMODs with crack depths were developed and validated against finite element (FE) analysis. The fatigue crack growth rates observed in the full-scale tests were then compared with existing BS 7910 and API 579 formulations. The comparison confirmed that the BS 7910 approach results in very conservative estimates of fatigue crack growth rates for axial flaws. The BS 7910 stress intensity factor formulation overestimated the bulging correction for axially oriented flaws. The API 579 fracture mechanics-based fatigue crack growth formulation combined with crack growth rate parameters developed in this program provided improved estimates for fatigue life. The fatigue crack growth rates for line pipe and ERW weld seams developed in this project were shown to be less conservative and better predictors for fatigue crack growth and represent a valuable tool for pipeline integrity management. The use of this information will enable pipeline operators to focus remedial actions on features that have the lowest estimated fatigue lives.

Axial strain inspection using the AXISS™ is an established tool in the pipeline operator’s toolbox to assess pipeline geotechnical threats and other strain related events. Consequently, there is a large database of axial strain data for several different pipelines operating in different environments and from multiple inspections at the same geographical locations. The Cheecham slope, located south east of Fort McMurray, Alberta, is a known geohazard site crossed by six individual pipelines. The lines were constructed between 1999 and 2013 and have a size range of 10” to 36”. Five out of the six lines, 12” to 36”, have been inspected using the axial strain tool. The pipelines inspected cover a range of characteristics including, different vintages, pipe diameters and positions in the ROW. These differences, and the ILI runs provide an insight into the effect of a landslide event on the strain response of these pipelines. Axial strain measurement of the multiple pipelines in the Cheecham slope’s ROW allows: i) a direct comparison between lines ii) evaluation of the strain profile across the slope iii) assessment of the magnitude of the axial strain in terms of pipe characteristics e.g. pipe vintage and mechanical properties. More importantly, the axial strain data may provide an additional tool to assess the effectiveness of strain mitigation steps carried out over the years. An increase in the frequency of axial strain ILI runs resulted in additional data being available and more importantly data from run to run inspections spread over months or sometime years. A single run captures the strain at the time of inspection but run to run inspections provide an additional comparative tool to evaluate and monitor pipeline movement. Two out of the five lines inspected have run to run axial strain data. This paper takes the Cheecham slope as a case study to discuss the benefits of run comparison of ILI axial strain data either by comparing strain values of repeated runs for a single line or by the cross comparison of strain responses of different lines in the same ROW. The paper aims to demonstrate how run to run analysis of ILI axial strain data can be implemented as part of geohazard risk management program to asses strain risk profiles of these locations and to assess the effectiveness of strain mitigation programs previously undertaken by operators.

Digitalization in the oil and gas industry has led to the formation of digital twins. Digital twins bring closer the physical and virtual world as data is transmitted seamlessly between real time sensors, databases and models. The strength of the digital twin concept is the interconnectivity of data and models. Any model can use any combination of inputs ( e.g. operator owned data sets and sensors, third-party databases such as soil composition or weather data, results from other models such as flow assurance, threat modelling or risk modelling). Consequently, the result of one model may become the input of another. This strength is also a weakness, as uncertain (or missing data) will lead to a great source of uncertainty and may lead to wrong results. Worst case scenarios have been used to solve this issue without success. This paper presents a new concept: probabilistic digital twins for pipelines. Probabilistic digital twins do not lose uncertainty as results pass from one model to another, thus providing greater confidence in the final results. This publication reviews the probabilistic digital twin concept and demonstrates how it can be implemented using gas pipeline data from West Pipeline Company, CNPC.

The tectonic fault, which is one of the most common geohazards in field, poses great threat to buried pipe segments. Pipes will process to buckling or fracture due to large strain induced by continuously increasing ground displacements during earthquakes. Therefore, it is imperative to conduct safety analysis on pipes which are buried in seismic areas for the sake of ensuring normal operation. However, the highly nonlinearity of pipe response restricts the proceeding of reliability assessment. In this study, a hybrid procedure combining finite element method and artificial neural network is proposed for reliability-based assessment. First of all, the finite element model is developed on ABAQUS platform to simulate pipe response to strike-slip fault displacements. Thus, the strain demand value (the peak strain value obtained by finite element model in each design case) can be collected for database establishment, which is the preparation for neural network training. Thoroughness of the strain demand database can be achieved by a fully comprehensive calculation with consideration of influencing factors involving pipe diameter and wall thickness, operating pressure, magnitude of fault displacement, intersection angle between pipeline and fault plane, and characteristic value of backfill mechanics. Sequentially, Back Propagation Neural Network (BPNN) with double hidden layers is trained based on the developed database, and the surrogate strain demand prediction model can be obtained after accuracy verification. Hence, the strain-based limit state function can be respectively determined for tensile and compressive conditions. The strain capacity term is simply assumed based on published papers, the strain demand term is naturally superseded by the surrogate BPNN model, and Monte Carlo Simulation is employed to compute the probability of failure (POF). At last, the workability of the proposed approach is tested by a case study in which basic variables are referred to the Second West-to-East natural gas transmission pipeline project. It indicates that ANN is a good solver for reliability problems with implicit limit state functions especially for highly nonlinear problems. The proposed method is capable of computing POFs, which is an exploratory application for reliability research on pipes withstanding fault displacement loads.

To improve the safety of a pipeline system, engineers use different methods to diagnose the hazardous pipeline accidents. However, most methods ignore the time dependence of pipeline failures. The aim of this paper is to provide a novel approach to analyzing the hazardous liquid pipeline incidents’ temporal structure. The database of hazardous liquid spillages from the US between 2002 and 2018 is collected by the Pipeline Hazardous Material Safety Administration of the US Department of Transportation. The result suggests that the whole oil pipeline incident sequence cannot be modeled as a Poisson (random and independent) process, which means that a hazardous liquid pipeline incident is not statistically independent from the time elapsed since the previous event. But the serious pipeline failures are random and unpredictable. The analysis also indicates that the equipment failure, corrosion, material failure and incorrect operation are the four leading failure causes, responsible for most of the total incidents. The study provides insights into the current state of hazard liquid pipelines in the US and baseline failure statistics for the quantitative risk assessments of such pipelines.

The United Kingdom Onshore Pipeline Operators Association (UKOPA) was formed by UK pipeline operators to provide a common forum for representing operators interests in the safe management of pipelines. This includes providing historical failure statistics for use in pipeline quantitative risk assessment and UKOPA maintain a database to record this data. The UKOPA database holds data on product loss failures of UK major accident hazard pipelines from 1962 onwards and currently has a total length of 21,845 km of pipelines reporting. Overall exposure from 1952 to 2016 is 927,351 km years of operating experience with a total of 197 product loss incidents since 1962. The low number of failures means that the historical failure rate for pipelines of some specific diameters, wall thicknesses and material grades is zero or statistically insignificant. It is unreasonable to assume that the failure rate for these pipelines is actually zero. In addition to product loss incidents, the UKOPA database contains extensive data on measured part wall damage that did not cause product loss, unlike the European Gas Incident data Group (EGIG) database, which also includes the UK gas transmission pipeline product loss data. The data on damage to pipelines caused by external interference can be assessed to derive statistical distribution parameters describing the expected gouge and dent dimensions resulting from an incident. Overall external interference incident rates for different class locations can also be determined. These distributions and incident rates can be used in structural reliability based techniques to predict the failure frequency due to external interference for a given set of pipeline parameters. The current distributions of external interference damage were derived from data up to 2009 and presented as Weibull distributions for gouge depth, gouge length and dent depth. Analysis undertaken for the COOLTRANS CO 2 pipeline project, undertaken by National Grid in the UK, has identified several improvements to the recommended UKOPA approach to external interference failure frequency prediction. This paper summarises those improvements and presents updated damage distribution parameters from data up to 2016.

Earthquake hazard management for oil and gas pipelines should include both preparedness and response. The typical approach for management of seismic hazards for pipelines is to determine where large ground motions are frequently expected, and apply mitigation to those pipeline segments. The approach presented in this paper supplements the typical approach but focuses on what to do, and where to do it, just after an earthquake happens. In other words, we ask and answer: “Is the earthquake we just had important?”, “What pipeline is and what sites might it be important for?”, and “What should we do?” In general, modern, high-pressure oil and gas pipelines resist the direct effects of strong shaking, but are vulnerable to large co-seismic differential permanent ground displacement (PGD) produced by surface fault rupture, landslides, soil liquefaction, or lateral spreading. The approach used in this paper employs empirical relationships between earthquake magnitude, distance, and the occurrence of PGD, derived from co-seismic PGD case-history data, to prioritize affected pipeline segments for detailed site-specific hazard assessments, pre-event resiliency upgrades, and post-event response. To help pipeline operators prepare for earthquakes, pipeline networks are mapped with respect to earthquake probability and co-seismic PGD susceptibility. Geological and terrain analyses identify pipeline segments that cross PGD-susceptible ground. Probabilistic seismic models and deterministic scenarios are considered in estimating the frequency of sufficiently large and close causative earthquakes. Pipeline segments are prioritized where strong earthquakes are frequent and ground is susceptible to co-seismic PGD. These may be short-listed for mitigation that either reduces the pipeline’s vulnerability to damage or limits failure consequences. When an earthquake occurs, pipeline segments with credible PGD potential are highlighted within minutes of an earthquake’s occurrence. These assessments occur in near-real-time as part of an online geohazard management database. The system collects magnitude and location data from online earthquake data feeds and intersects them against pipeline network and terrain hazard map data. Pipeline operators can quickly mobilize inspection and response resources to a focused area of concern.

An extensive experimental program to characterize the Charpy-V-notch (CVN) impact toughness of ten contemporary Electric Welded (EW) pipes was recently completed to establish a database to support the revision of the EW seam weld Charpy toughness testing requirements in Canadian Standards Association (CSA) Z245.1-14. The toughness in these welds is lowest at or near the weld bond line (BL) within a narrow zone ±≈0.5 mm wide. It is feasible and desirable to position the BL notch to a precision to match this width, i.e. ±0.5 mm from the BL. In this paper, typical results of microstructure, micro-hardness, CVN toughness (i.e. absorbed energy) as a function of temperature and notch location, and fractography will be presented. CVN absorbed energy requirements for EW welds in CSA Z245.1 have been determined using a failure assessment diagram (FAD) procedure. The values of required CVN estimated from the FAD are close to those specified in CSA Z245.1-14 but are higher than the specification in CSA Z245.1-18.

In this paper, three-dimensional finite element models are developed to simulate full-scale burst tests of corroded pipes containing multiple naturally occurring corrosion anomalies. Both the von Mises and Tresca yield criteria and associated flow rules are employed in finite element analysis (FEA). For the Tresca criterion, the corresponding constitutive model subroutine is developed and incorporated in the FEA. The accuracy of FEA is investigated by comparing the burst pressures observed in the tests and corresponding burst pressures predicted using FEA. The implications of using the von Mises and Tresca criteria for the accuracy of the predicted burst pressure are investigated. Sensitivity analyses are also carried out to investigate the impact on the predicted burst pressure due to the mesh density in the corroded region, characterization of the geometry of the corrosion cluster and different types of element (e.g. solid and shell elements) used in FEA. The results suggest that the Tresca criterion always underestimates the burst pressure and the von Mises yield criterion predicts the burst pressure accurately. This study demonstrates the feasibility of using high-fidelity FEA and the Tresca yield criterion to simulate full-scale burst tests of corroded pipes and therefore establish a large database of burst pressure capacities of corroded pipes that can be used to develop an accurate, practical burst pressure capacity model amenable to the pipeline integrity management practice.

Hydrostatic pressure testing is the most widely accepted approach to verify the integrity of assets used for the transportation of natural gas. It is required by Federal Regulations 49 CFR §192 to substantiate the intended maximum allowable operating pressure (MAOP) of new gas transmission pipelines. The Pipeline and Hazardous Materials Safety Administration (PHMSA) Notice of Proposed Rulemaking (NPRM) with Docket No. PHMSA-2011-0023 [1], proposes an additional requirement for MAOP verification of existing pipelines that: i) do not have reliable, traceable, verifiable, or complete records of a pressure test; or ii) were grandfathered into present service via 49 CFR §192.619(c). To meet this requirement, the NPRM proposes that an Engineering Critical Assessment (ECA) can be considered as an alternative to pressure testing if the operator establishes and develops an inline inspection (ILI) program. The ECA must analyze cracks or crack-like defects remaining or that could remain in the pipe, and must perform both predicted failure pressure (PFP) and crack growth calculations using established fracture mechanics techniques. For assets that cannot be assessed by ILI, however, the implementation of an ECA is hindered by the lack of defect size information. This work documents a statistical approach to determine the most probable PFP and remaining life for assets that cannot be assessed by ILI. The first step is to infer a distribution of initial defect size accumulated through multiple ILI and in-ditch programs. The initial defect size distribution is established according to the as-identified seam type, e.g. low-frequency electric resistance weld (LF-ERW), high-frequency electric resistance weld (HF-ERW), flash weld (FW), single submerged arc weld (SSAW), or seamless (SMLS). The second step is to perform fracture mechanics assessment to generate a probabilistic distribution of PFPs for the asset. In conjunction with the defect size distribution, inputs into the calculation also include the variations of mechanical strength and toughness properties informed by the operator’s materials verification program. Corresponding to a target reliability level, a nominal PFP is selected through its statistical distribution. Subsequently applying the appropriate class location factor to the nominal PFP gives the operator a basis to verify their current MAOP. The last step is to perform probabilistic fatigue life calculations to derive the remaining life distribution, which drives reassessment intervals and integrity management decisions for the asset. This paper will present some case studies as a demonstration of the methodology developed and details of calculation and establishment of database.

Statistical data available from several international sources, such as the reports provided by the European institutions EGIG, CONCAWE and UKOPA, as well as by the American Department of Transportation – DOT, indicate that pipelines represent the safest mode of transportation for hydrocarbons and other dangerous products when compared to other alternatives, such as road, rail, waterway, etc. Operators ensure a high level of safety of their pipelines by investing large amounts of effort and resources in accident prevention, efficient contingency procedures, environmental protection and reliability along the life cycle of their assets. However, the pipeline industry, both in Brazil and abroad, is frequently asked to demonstrate their safety performance both by environmental and regulatory agencies, as well as by society, considering the assets already in operation and also those that will still be built (new pipelines). Such requests are based on the most opened and detailed communication between pipeline operators and the other stakeholders involved. In this context, the organized and standardized collection of data related to pipeline failure events, such as failure mechanisms and their consequences, along with relevant and specific data regarding the assets and their operations, is essential to foster the process of knowledge construction on this topic. It allows generating consistent information both to meet the stakeholders’ requests and to improve risk management of pipelines by the operators, ultimately supporting decision-making. Therefore, this work aims to create a Brazilian Pipeline Incident Database, considering firstly gas pipelines and oil pipelines operated by TRANSPETRO, a PETROBRAS Subsidiary. This research intends to study the characteristics, the architectures, the assumptions and the principles adopted by the international pipeline failure databases currently available, considered here as benchmarks, in order to propose an analogous and specific structure for the reality of the Brazilian Pipeline System.

The United Kingdom Onshore Pipeline Operators Association (UKOPA) was formed by UK pipeline operators in 1996 to provide a common forum for representing pipeline operators’ interests in the safe management of pipelines. This includes ensuring that UK pipeline codes include good practice, and that there is a common view in terms of compliance with these codes. To achieve this UKOPA has carried out a number of technical initiatives and studies to establish good practice requirements for UK operators which aim to ensure pipeline integrity is managed such that the risks posed by pipelines are as low as reasonably practicable (ALARP) in accordance with UK goal-setting safety legislation. UKOPA has developed Quantitative Risk Assessment (QRA) methodology which is published in UK standards and detailed guidance on the derivation of pipeline specific external interference failure frequencies, which have previously been published at IPC. The external interference frequency model is based on an analysis of data recorded in the UKOPA fault database which records product loss and damage data for UK major accident hazard pipelines from 1962 onwards. The database currently has a total length of 22,158 km of pipelines with over 877,598 km years of operating experience. The failure data is sparse, with only 192 product loss incidents, so where possible damage data and engineering failure models are used to develop reliable pipeline failure rates. To date this work has concentrated on the random failure causes of external interference and ground movement, which generate the major residual risk posed by pipelines in the UK. The majority of the UK pipeline population is now older than the original 40 years target design life. Consequently, the current UKOPA strategy is focused on the issues which affect the integrity and risk management of ageing pipelines. This requires the investigation of potential damage mechanisms which may affect older pipelines, including the impact of degradation of components which are no longer allowed by current standards, such as pipeline sleeves (casings), the degradation of damage which occurred during original construction and the assessment of the impact of material and weld quality standards typical of older pipelines. The work currently being undertaken by UKOPA involves first the assessment of the impact on integrity, then the development of engineering failure models, and finally the application of the models to the UK pipeline population to predict failure frequencies which are then compared with recorded data. This paper describes the assessment of the UKOPA damage data to identify indications of age related damage and deterioration trends, the development of practical integrity models for the assessment of pipeline sleeves and construction dents and the application of these models to the UK pipeline population. It also discusses an approach developed for UKOPA ethylene pipeline operators to assess population developments adjacent to existing pipelines.

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

In the early phases of a pipeline project, the lack of data available for routing results in multiple routes being considered and interactions with land owners with only a general route. As a consequence, multiple survey programs are undertaken only to collect data that often is not being used, or site revisits are required to collect additional survey data. Repeated visits by survey crews to the field results in considerable cost and schedule delay to the project. A project was undertaken to reduce these costs and schedule impacts by replacing the need for survey work during FEED by utilizing remote sensing data and Artificial Intelligence (AI). This paper outlines the methods for collection of High Density (HD) LiDAR and high resolution imagery and then using AI to automatically identify all above ground features. This technique has proven to provide data of sufficient accuracy and completeness to conduct Pre-FEED and FEED level routing and engineering of a pipeline project. When survey is required, it is only to collect below ground features and to collect or verify data in very specific detail. Additionally, when required for legal or engineering reasons, survey work can be conducted more efficiently by providing the crews with a field database of the features already captured and means for updating the database with the data they collect or verify.

Reliability, Availability and Maintainability (RAM) models were first developed in Enbridge Liquids Pipelines in 2006 and in the last 3 years have contributed over $200 Million in capital cost avoidance while maintaining or improving the reliable design and operation of the pipeline system. These models constitute a very effective, factual and dependable tool to assess the throughput performance of a pipeline system over its entire life cycle or a specified time of interest. In addition, the RAM model cost is a small fraction of the overall monetary benefit, in the order of 1%, hence making RAM models a highly leveraged activity. The concept of a RAM model stems from Reliability Block Diagram methods (also known as Dependent Diagrams). Interaction of large, complex and multi layered systems can then be analyzed using the Monte Carlo simulation methods (or Stochastic Discrete Event Simulation) hence quantifying the output of the entire system with greater accuracy than other estimating tools or methods. Over 10 years, Enbridge Liquids Pipelines has developed its own failure database for equipment and operational events consequently almost all model inputs are based on in-house data rather than industry generic data, making the model output more robust, accurate and appropriate for internal use. Initially, in Enbridge Liquids Pipelines, RAM models were mainly built to assess and confirm the design capabilities of future pipelines designs and assist in the optimal selection of specific design options. Because of the effectiveness of the tool combined with the current cost constrained business environment, the company is moving towards building RAM models for assets already in operation in order to optimize their performance. This is proving to be an extremely cost effective addition to internal decision making processes. The approach has been used in risk based budgeting, asset maintenance, design modifications and throughput optimization initiatives. In various industries including Oil and Gas, RAM models have proven their worth over time as an effective cost avoidance tool. This approach has now been successfully deployed in the Pipeline Industry at Enbridge. As an example, a RAM model conducted during the design phase of a pipeline project saved $28 million in capital by proving that an additional storage tank and significant new infrastructure was not required. Another benefit of RAM models has been their ability to confirm or counter stated assumptions by internal stakeholders. Equipment upgrades and equipment sparing decisions are often seriously debated and costly decisions may not always be based on complete economical foundations but rather on avoiding past negative experiences or by following basic guidelines that are less than optimal. When a project or operational team needs to find an alternative, a RAM model is a tool of choice to evaluate, and justify the best option. Because of its proven value, RAM models are now an integral part of Enbridge Liquids Pipelines Design Standards and are used on all large projects. Models recently built for operational pipelines delivered similar value so in the near future the work will be expanded to encompass the entire existing network of integrated pipelines to improve on performance and operational costs.

Generating a tensile strain capacity (TSC) prediction model is a difficult challenge in applied mechanics. Because current models are relatively new and extensive strain-based design (SBD) pipeline service experience does not exist, rigorous model validation using full-scale tests (FSTs) is paramount. The lessons learned from 159 FSTs were presented previously and the data base has grown to 173 tests. This data base is used to assess the accuracy of a relatively new TSC prediction model. The new model simulates a single, surface breaking weld flaw; however, some of the FSTs contained interacting or embedded flaws or unintentional weld defects, while others failed by brittle fracture, and still others experienced welding problems rendering them unsuitable for model validation. Of 173 tests, a smaller number (122, 101, or 89 depending on the goal) is used for comparison to the new model. This paper describes (1) the importance of reliable FSTs, (2) how the 173 tests were judged for suitability in model accuracy assessment, and (3) the use of the FST data to develop a safety factor for strain-based engineering critical assessment (SBECA). The safety factor is generated from a 95% upper confidence limit on the ratio of predicted-to-measured TSC. The safety factor is 1.88. Using the new model and this safety factor, a TSC prediction equation is provided for use in SBECA. The practical meaning of this is that if either TSC or tolerable defect size is calculated using the new model, then the probability of being non-conservative is estimated to be 5%.

Although the traditional method based on stress analysis is simple and convenient, the main limitation is that it does not reflect the actual failure mechanisms (or limit states). A pipeline network database of about 40 thousand kilometers comprising 258 design cases that represent combinations of steel grade, diameter, pressure, and location class is established, in order to evaluate and improve the design factors specified in the Chinese standard “Code for design of gas transmission pipeline engineering” (GB 50251). Referring to the research report “Target Reliability Levels for the Design and Assessment of Onshore Natural Gas Pipelines” accomplished by C-FER in 2005, the critical wall thicknesses and corresponding equivalent design factors are calculated by using reliability-based method to meet specified reliability targets. The research shows that the equivalent design factors obtained by Reliability-Based Design (RBD) method tend to increase as the pipe diameters get larger. The new design factors are smaller than those specified in the design code for pipelines with small diameter in location class 1 and 2, and larger than those in the design code for the other pipelines. Therefore, design factors are modified in each location class. The new factors are specific to pipes with small diameter (D ≤ 508mm), medium diameter (508mm < D < 711mm), and large diameter (711mm ≤ D ≤ 1219mm), thus enhancing the rationality and practicability of design factors.

Geographical Information Systems, Data trending, and Risk Assessment Software are now available to help pipeline operators execute safe, cost effective maintenance programs. However, to use these analytical tools effectively, large amounts of data pertaining to the integrity of the pipeline system and its environment are required. For this reason, pipeline rehabilitation programs have evolved into complex data collecting procedures, the success of which depends on the ability to efficiently obtain reliable, consistent and accurate information. This article will describe new software technology and Quality Control programs, relating to inspection personnel, which have been developed to increase the efficiency and reliability of the information collected during a pipeline excavation. The pertinent functions of software programs discussed will involve compatibility between databases, on site data validation, code calculations, communications and CAD drawings for a comparison with In Line Inspection results. As well, the need for quality control or training programs will be discussed addressing both the theoretical and practical applications of pipeline integrity and it’s relevance to quality data collection. Previous projects using these approaches will be presented showing their effectiveness in significantly increasing the efficiency and accuracy of the information collected while reducing overall inspection time and cost.