Abstract
This study collected and analyzed field data to validate the probabilistic model developed previously for predicting internal corrosion threats resulting from condensed water from nominally dry natural gas. Model-predicted wall loss was compared to actual measurement to validate the model. One past failure case from the National Transportation Safety Board(1) due to internal corrosion and in-line inspection (ILI) data from five pipeline operators were collected and used to validate the Model. Two of the data sets indicate wall loss that is either evenly distributed at all locations around the circumference of the pipe or predominantly at the top of the pipe, which is in agreement with the negligible wall loss predicted by the Model. Another two sets of data show significant wall loss occurring at the bottom of the pipe, which is in agreement with non-negligible risk of internal corrosion predicted by the Model. The 5th data set confirmed the analysis of ILI data uncertainty and corroborated the validation results. For the failure case, the prediction is in good agreement with the post-failure examination. Although uncertainties exist in both Model predictions and ILI measurements, the wall loss predictions from the Model are in good agreement with trends seen in the ILI measurements.
Introduction
The internal corrosion (IC) threat in dry gas pipelines is low because the water content is very low as a result of control under a tariff limit [5 or 7 lb/MMscf (0.08 or 0.1 g/Nm3). The threat may increase, however, when liquid water enters the pipeline via processing upsets and/or forms from condensation, pressure drop, hydrotest residual, and/or condensate intrusion from side branches. The threat can be confirmed through methods including in-line inspection (ILI), pressure testing or direct assessment; each method has limitations and is costly to implement. It is important that methods are developed to identify and prioritize the likely locations of IC threat. Equally important are methods that can be developed to determine conditions where an IC threat is extremely unlikely and thus inspections could otherwise be exempted or the reassessment interval extended. With these methods, an operator would be able to evaluate whether the current operation of its pipeline has an IC threat that is extremely unlikely or how to adjust its operation to reduce the IC threat so that it becomes extremely unlikely. If the IC threat is determined to be extremely unlikely, the operator may be able to make a convincing case to regulators that allows for extending the reassessment interval of ILI, pressure testing or direct assessment. In responding to this need from the pipeline industry, probabilistic risk analysis models for dry gas [herein referred to as "dry gas internal corrosion threat (DGICT) model" or the "Model'] were developed and enhanced to determine the likelihood of IC threat for given operating conditions due to water condensation1-3
