TransGas

Recent close-interval potential surveys have raised concerns about the accuracy of potential measurements on some older, poorly-coated pipelines. Two significant sources of error were identified: metallic IR-drops and equalization currents. These resulted in measured on and off potentials which differed by hundreds of millivolts from the true potentials, even though the measurements were conducted in accordance with industry best practice. Examples of these phenomena will be discussed and the electrical theory will be explained. Both interrupted test post surveys and close-interval potential surveys are susceptible and these errors can be difficult to detect. This can have a significant impact on interpretation of survey data, External Corrosion Direct Assessments, and remedial program decisions. Guidance for identifying when these issues may be relevant and methods for detecting and compensating for these issues will be provided.

The risk of pipeline failure is a measure of the state of knowledge of the pipeline; improved knowledge of the pipeline reduces the uncertainty and therefore can reduce the associated risk. Specifically for corrosion defects, the knowledge of the number and size of defects is often obtained using in-line inspection tools which have uncertainty associated with their measurement capabilities. Quantitative Risk Assessment (QRA) is a methodology that objectively assesses a range of pipeline integrity threats including the threat of corrosion failure. QRA can incorporate the impact of significant sources of analysis uncertainty, such as feature sizing in risk estimates. This paper discusses an application of QRA used to evaluate the operating risk of high pressure transmission pipeline segments in the TransGas system. Specific examples are described in which the inspection tool sizing uncertainty was shown to exert a significant influence on the calculated risk levels. In carrying out the analysis, the failure probability models selected were dependent on the nature of the integrity threat and the type of information available for each pipeline. For the assessment of corrosion integrity, the results of in-line inspections were used directly in determining failure likelihood. For the other threats including equipment impact, geotechnical hazards, manufacturing cracks and stress corrosion cracking, the probability of failure was estimated from historical failure rates with adjustments to reflect line-specific conditions. Failure consequences were estimated using models that quantify the safety implications of loss of containment events. Using these models, safety risk measures were calculated along the length of each pipeline. The results of the analysis show the benefit of the use of inspection technologies with improved sizing accuracy, in terms of reduction in expected operating risk.

Stress Corrosion Cracking (SCC) is a major integrity threat for many gas and oil pipeline operators. Once SCC is detected on a pipeline, if the severity of the SCC is determined to be class III or IV, it is the operator’s responsibility to ensure that the risk of a SCC failure is adequately mitigated. This paper discusses several design strategies implemented by TransGas for the purpose of this UT ILI run including: designing a custom launcher to facilitate easy insertion of batching pigs, UT ILI tool, and batching liquid; development and use of a flow / speed control system utilizing pressure differential readings from orifice meters, as well as many of the logistical challenges associated with the project.

TransGas undertook a risk-ranking project for storage facilities as the first step in the process of evaluating the financial and life-safety risk associated with the eight storage facilities that they operate in Saskatchewan, Canada. Based on this analysis, two salt cavern storage facilities were selected for a quantitative risk assessment. The most cost-effective maintenance actions for each cavern were determined as follows: Fault trees were prepared for all of the identified failure scenarios. Several unique computer models were developed to predict the failure rates of the events identified in the fault trees and the consequences associated with both sub-surface and atmospheric releases from the storage facilities. Both life-safety and financial risk were considered in the analysis. For each of the caverns, a number of potential maintenance scenarios were selected that address the dominant failure causes. Life-safety risk was assessed first and compared to the TransGas tolerance. A cost optimization analysis was then carried out in which the total expected future cost associated with each maintenance option was amortized over the benefit period and compared to the total expected future cost associated with the current maintenance practice. The paper describes the risk analysis and cost optimization approach and provides case study examples of the caverns analyzed and the recommendations reached in each case.

The quantitative risk assessment tool was used to calculate the failure rates, failure consequences and risk levels along the pipeline. Safety risk was characterized by the individual risk ratio, which was defined as the maximum individual risk associated with a given segment divided by the tolerable individual risk. Tolerable individual risk values were defined as a function of population density following the approach developed by MIACC and the UK HSE. Financial risk was expressed in dollars per km-year and included a dollar equivalent for public perception. The recommended maintenance plan was defined as the minimum cost option that achieved a tolerable safety risk. The first step in developing the plan was to identify all segments that do not meet tolerable risk criteria (i.e., segments with an individual risk ratio greater than 1). For each of these segments a number of potential maintenance scenarios that address the dominant failure threats were selected. A cost optimization analysis was then carried out in which the total expected cost associated with each maintenance option was calculated as the sum of implementing the option plus the corresponding financial risk component, amortized over the inspection interval. This analysis was used to identify the minimum cost alternative that meets the individual risk constraint. Outcomes of the analysis included the best maintenance option (e.g., inline inspection, hydrostatic test) and the optimal time interval for segment re-evaluation.