US pipeline integrity management regulations require operators to rank the risks caused by their operations. Many operators use qualitative methods for this risk ranking process. Such methods have several benefits including simplicity and flexibility. Unfortunately, they rely heavily on engineering judgment and produce results that are very specific to the pipeline system(s) being ranked. This makes it extremely difficult to relate the outputs from different systems or companies within an organization. This paper describes the development and application of a risk ranking approach that requires less judgment and provides the user with an estimate of the true risk of operating the pipeline. Quantitative methods, based on an understanding of structural mechanics, are applied to seven of the nine threat categories listed in ASME B31.8S in order to determine the pipeline’s reliability. An assessment of risk to life is achieved by combining the output from structural mechanics models with a quantitative consequence of failure model. The software operates on a GIS platform, making it easier to demonstrate compliance with the integrity data management requirements that are now part of the relevant federal codes. Results produced from the quantitative approach have been compared to those generated by qualitative methods, in a case study. This illustrates some important differences between the two and show that a more rigorous, quantitative approach can provide the operator with significant benefits including the ability to generate meaningful results with less data. In particular, quantitative methods have the potential to allow operators to move towards a more performance-based approach to their ongoing integrity management processes.

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

Situations can arise where the condition of a pipeline system is poorly known. This may be due to a variety of operational or commercial reasons. Failures will eventually occur if time dependent degradation mechanisms are active. While an appropriate response may be to inspect or hydrotest, this is generally not feasible within a short time frame and integrity assessments or replacements must therefore be prioritized. This paper looks at an ageing upstream pipeline system subject to internal corrosion. A case study is presented in which a system approaching its original design life is required to carry fluids from reservoirs now forecast to be productive for another 50 years. Fluids include sweet or sour gas, crude oil and injection water. Design data are available but inspection information is sparse with less than 10% of lines inspected by ILI; coupon data and well production forecasts are available. The challenge was to prioritize line replacements according to the remnant life of each pipeline, based on the limited available data. Current condition was measured for lines where ILI data were available. A corrosion risk assessment was conducted to identify credible degradation mechanisms. The pipelines were then grouped according to the fluids being transported. This enabled an estimate of current condition for all pipelines based upon the limited inspection and coupon data. In order to predict the remnant life it was necessary to estimate the future corrosion rates, again for all lines. A number of approaches could be used for estimating future corrosion rates. These include basing the rates on historical inspection data or using corrosion modeling techniques. The paper describes a hybrid method that synthesises these two approaches to allow a corrosion rate distribution to be postulated for calculating remnant life. In addition, the options for future corrosion rate estimation are described and the advantages and disadvantages of each one discussed.

The BG Elastic Wave in-line crack detection vehicle was used to inspect 213.5 km (133 miles) of Interprovincial Pipe Line Inc’s (IPL’s) Line 3. Rigorous analysis of the inspection data, concentrated on the seam weld and surrounding region, identified 73 sites for excavation. Pressure retaining sleeves were fitted at 17 locations. Of these, the most severe defect noted was a 25 mm (1 inch), 40% through wall long seam shrinkage crack. This was the only feature exceeding a size predicted to possibly fail under hydrotest to 100% SMYS. Twelve other cracks were sleeved, all of which were measured to be between 20% and 35% through wall. Minor imperfections were found at the majority of those reported locations which were not sleeved. Following completion of remedial work, 198 km (124 miles) of Line 3 was hydrostatically tested at pressures up to 100% SMYS, including 156 km (98 miles) that had been inspected by the Elastic Wave vehicle. There were no leaks or ruptures under hydrotest, demonstrating the ability of the tool to reliably detect cracks in the seam weld and surrounding region that were smaller than would have been found by hydrostatic testing alone.