Executing an appropriate response to conditions affecting pipeline integrity, as predicted by in-line inspection tools, can be affected by the rate of growth for time dependent threats such as metal loss due to corrosion. Corrosion growth rates can be estimated from predictive models considering the known corrosion mechanisms. Corrosion rates can also be determined from measurements of metal coupons exposed to the corrosive environment or from comparisons of pipe wall measurements over time. In-Line Inspection (ILI) assessments have been used by industry to provide wall loss measurements for corrosion growth rate determination with estimates developed from single ILI assessments based on pipeline age or comparison of wall loss measurements from consecutive ILI assessments using the approaches of feature list positional matching, box or full signal matching. This paper presents a case study comparison of corrosion growth rate results obtained from a gas transmission pipeline using the currently available industry procedures and the implications of each within the context of response strategies to ILI predictions.
Pipeline integrity management programs often employ in-line inspection (ILI) tools and they have proven extremely valuable for locating pipe wall flaws before they become a critical size and risk pipeline failure. The ASME Code Supplement B31.8S addresses the management of system integrity for gas pipelines and considers the use of in-line inspection (ILI) as an integrity assessment method used to locate and preliminarily characterize metal loss indications in a pipeline. A schedule for responding to anomalies, identified by ILI, through examination and evaluation is provided within the ASME Standard (specifically Figure 4) that was developed considering a conservative assumption for corrosion growth rate based on industry research (GRI-00/0230) which is to be considered within data analysis to insure the pipeline segment does not warrant special consideration for ILI response.1
