PIPELINE INTEGRITY ASSESSMENT
t is common practice for pipeline operators to carry out in-line inspections (ILIs) and subsequent ultrasonic thickness (UT) field verifications where possible. Information obtained by these methods can be used to perform a pipeline integrity assessment. Appropriate remedial actions can then be applied, such as pipeline repairs or de-rating.
I
Often, it is of great value to accurately determine an ongoing corrosion rate to extrapolate the current size of MLFs to any number of years in the future and estimate predicted feature sizes. Operators are then able to make informed decisions regarding repair schedules, extending/ reducing ILI intervals and carrying out pipeline de-rating only when it is required.
Unfortunately, accurate prediction of an ongoing corrosion rate is often difficult due to a lack of actual or reliable operating data through changes in operator/ownership, high staff turnover, changes in internal organisation, and an ageing pipeline infrastructure.
Missing data can result in either overly pessimistic or optimistic assumptions being made with regard to the corrosion rates and conditions within a pipeline. The former could lead to increased inspections or premature de- rating (with corresponding cost implications), while the latter
Inspection Location
1
2 3 4 5 6 7
Year 6 ILI Data %WT Loss
37 21 22 26 17 18 14
INDUSTRY NEWS
Inspection Year 1
6
No. Internal Metal Loss Features Recorded 3004 13173
Table 1: Selected ILI data.
could lead to assuming non- corrosive conditions are present (with corresponding increased risk in operational problems, such as unexpected pipeline failure). This stresses the importance of accurate integrity assessment.
Example case study – crude oil pipeline An integrity assessment was required on a crude oil pipeline with the following specifications:
• Nominal wall thickness (WT) = 7.14 mm.
• Pipeline age at time of assessment = 9 years.
• Design pressure = 65 barg, de- rated to 30 barg. • Normal operating pressure = 17 barg.
• Design life = 30 years. The operator had predicted a remaining life of 9 years for a MAOP of 30 barg, i.e. an estimated total operational life of 18 years as opposed to the intended 30 years, based on an ongoing internal corrosion rate of 0.26 mm/yr, extrapolated from the worst case MLF as recorded during the latest UT verification campaign. As a result, extensive repair schedules were
organised. An independent pipeline condition and integrity assessment was conducted to advise appropriate operational and/or maintenance activities.
Step 1 – Data collection and review • Data for 2 x ILIs, performed in year 1 (6 months into operation) and year 6.
• Pipeline topography. • UT field verification readings. • Information from process/ pipeline design documentation.
Step 2 – Inspection data examination and analysis In the absence of suitable operating and process data, an ongoing corrosion rate could only be determined using inspection data. It became apparent that the operator’s approach to calculate a metal loss rate of 0.26 mm/yr was not appropriate, as explained herein.
Review of operator’s approach Table 1 provides selected data obtained from the ILIs, and Table 2 shows all of the UT data that had been recorded for the pipeline, as well as the most
Year 1
Not inspected Not inspected Not inspected Not inspected 18.77 17.37 10.36
8 23 14.50 Year 3
Not inspected Not inspected Not inspected Not inspected 18.77 20.17 10.36 13.17
UT Data – %WT Loss Year 6 30.14
20.14 32.17 29.85
Not inspected Not inspected Not inspected Not inspected
recent corresponding ILI data for each examined location. One issue was that a direct comparison had been made between the year 6 ILI and UT data at inspection locations 3 and 4, with all pipeline WT data taken at face value. As the UT feature measurements were deeper, it was deemed that pipeline corrosion required immediate attention. Also, the ongoing corrosion rate of 0.26 mm/yr was based on the amount of metal lost at the deepest year 9 UT measured feature (28.57% WT), assuming a time interval of 8 years.
ILI/UT data examination Comparing ILI and UT data from year 6 at face value for location 3 would imply that the feature had increased in depth by 10% WT in the same year. No appreciation was given to the possible sources of error in the inspection methods, particularly significant when considering ILI tool readings. Furthermore, calculating an average corrosion rate for an 8 year interval and most recent UT reading taken at location 1 did not seem appropriate given the other data that had been obtained.
Deepest Internal Metal Loss Feature (%WT) 29 37
Year 8 32.77
20.17
Not inspected 27.17
Not inspected Not inspected Not inspected 17.65
Table 2: Internal inspection data at various pipeline locations between years 1 – 9
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Year 9 28.57
20.16
Not inspected 27.17
Not inspected Not inspected Not inspected 17.36
IMT August/September 2014 15 IMT August/September 2014 17
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