Area Legislation 152: Updated Prerequisites For Boards And Buildings
Internal Inspection Of Wet Gas Lines Subject To Top Of Line Corrosion
The Bongkot field is a high CO2 (>20%) wet gas field located in the Gulf of Thailand. Thirteen infield carbon steel sea lines are laid in 80 meters of water. The lines sizes are 14 to 22. Almost 2/3 of the lines circumferences remain in contact with sea water; 1/3 buried on the sea bed by natural burial. The average flowing temperature at wellhead is about 90oC but declines rapidly to almost ambient temperature after a few kilometres. The major part of heat transfer through the pipe wall takes place along the first 500 meters after touch down. Due partial line burial, heat exchange takes place on the upper half section in contact with relatively cool sea water current (18 deg C) causing severe water condensation on the internal pipe surface. The flow regime is stratified at the inlet of the dogleg. Top of Line Corrosion (TLC) is expected along the first few kilometres. Some of lines were inspected by Magnetic Flux Leakage (MFL) inspection tools and severe TLC was detected. Being confronted with the decision to de-rate the pipeline or even worse to repair some corroded sections, the authors have tried to obtain accurate remaining wall thickness measurement by other mean than Magnetic Flux Leakage pig. IRISPig was developed and the new inspection of one of the lines shown only 50% of the thickness loss measured by MFL.
CORROSION MITIGATION AND FIRST INSPECTION RESULTS
For the development of the Bongkot field, carbon steel was used with 5 mm of corrosion allowance. Selections of pipeline material and corrosion control system was based on the corrosivity evaluation considering CO2 content of the effluent, operating conditions and produced water chemistry. However, no information was available concerning the acetic acid content of the effluent, which is very important for top of line corrosion, during the first phase of filed development. The field conditions being considered as very corrosive, corrosion inhibitor selection for the bottom line corrosion control was a critical issue. A water soluble corrosion inhibitor was selected after intensive laboratory testing(1). Field testing of the selected product confirmed laboratory results as the corrosion rates in the topside piping was reduced to less than 0.1 mm/y. The same product has been continuously injected at the well head for the protection of top side facilities and sealines since the production start up in mid 1993.
The first magnetic flux leakage (MFL) pig surveys carried out in 1994 (one year after first gas) gave no corrosion warning, and the subsequent surveys were set at 3 year intervals. During the 1998 campaign a pattern of TLC mainly from the 10 o?clock to the 2 o?clock position was detected along the first 500 meters (from the Wellhead Platforms) of the pipelines. Moreover, during subsequent inspections (2000 and 2002), the TLC was noticed to continuously propagate in width, length and but not in depth (surprisingly, the deepest features were reported declining). However longer sections of lines were found affected during subsequent inspections.
Following the first indications of TLC, a new york local law 97 laboratory study was initiated for corrosion inhibitor selection for batch treatments. Laboratory tests showed that water soluble corrosion inhibitors have better performances to control TLC than oils soluble ones(2). The corrosion inhibitor which has been used for the continuous injection was found to be very effective also for top of line corrosion control. Regular batch treatments have been implemented in all sealines using double pigs (diluted inhibitor is placed between two pigs).
