The study presents the internal corrosion direct assessment (ICDA) of a 48” x 18.7 km liquid petroleum pipeline carrying crude oil from a subsea pipeline end manifold (PLEM) to the onshore crude oil tank facilities. The pipeline has handled over 100 different compositions of crude oil since commissioning of its operations in 2006. Three (3) hydrotests have been done for the offshore section (6.4 km) of the pipeline and the seawater used for the hydrotest was left stagnant in the pipeline for a cumulative period of 293 days since 2006. The pipeline had no internal corrosion monitoring program in place and had no baseline internal corrosion assessments done at the commencement of the ICDA in March 2015.
While performing ICDA, multiphase flow modeling was carried out to predict the pressure drop, temperature drop, inclination angle and flow regime variations along the pipeline. The most probable locations of water accumulation and solids deposition were predicted along the pipeline following Liquid Petroleum ICDA (SP0208-2008)1. The corrosion rates along the line were quantified using Multiphase Pipeline ICDA (SP0116-2016)2. The offshore section of the pipeline had higher predicted wall loss (%) in comparison to the onshore section of the pipeline. This was attributed to the prolonged exposure to of the offshore section of the pipeline to untreated seawater post hydrotest.
Detailed examinations at the selected sites based on the highest probability of internal corrosion showed good correlations between the predicted wall loss and the actual measured wall loss where at all of the assessment sites the predicted versus actual wall loss (%) were within the ±10% criteria as required by the MP-ICDA (SP0116-2016) standard practice.
Key words: internal corrosion, direct assessment, subsea pipeline, hydrotest