A buried carbon steel gas flowline suffered from accelerated external corrosion after one-year operation. The flowline was protected by an impressed current cathodic protection and liquid epoxy polymer coating system. Root cause analysis revealed that coal seam oxidation under wet condition generated an aggressive acidic soil environment around the pipe. The coating and cathodic protection system in a low pH and elevated temperature (90-110ºC) environment was not able to provide adequate protection from external corrosion for this flowline.
A 16-inch 52km long gas flowline in southern Sumatra was shut down in the middle of December 2007 due to an external coating failure and corrosion found by a scheduled corrosion survey. The flowline was newly built and had been in operation for about 11 months. The coating failure was detected by a direct current voltage gradient (DCVG) survey and the external corrosion under the coating was found by excavation. The corrosion site was located about 250 meters away from the gas well. There were multiple areas with coating damage and wall loss due to external pitting corrosion. The flowline was API-5L-X52 grade carbon steel. Operational temperature and pressure were 90-110ºC (150ºC maximum) and 1000-1300 psi (6.9~9.0 MPa) respectively. The corroded pipe section was buried 1.5 to 2 m deep in a downhill coal seam. The external surface of flowline was coated with a liquid epoxy polymer coating. An impressed current cathodic protection (ICCP) system was installed at the gas plant end of the flowline. Site investigation and laboratory analysis showed that the surrounding soil was highly acidic. The close interval potential survey (CIPS) data indicated the cathodic protection potential met accepted standards. In the tropical southern Sumatra Island, the oxidation of sulfur in the coal can generate a highly corrosive sulfuric acid in the soil. The high temperature around the pipe surface may have concentrated the acid. At low pH and high temperature conditions, little knowledge is available in literature regarding coatings with CP. A DCVG survey also showed that other buried flowlines in the same area were also susceptible to external corrosion. A research project was initiated to investigate this corrosion issue and evaluate the coating stability with CP operational parameters.
The corroded section of the flowline was buried in a coal seam rich soil. Other parts of the flowline were buried in the wet soil. A nearby coal seam has experienced spontaneous combustion several times since the start of operation. Figure 1 shows the geographic location of the flowline. DCVG survey and site excavation revealed coating failure and external corrosion on the pipe. Figure 2 shows the excavation site and the soil condition. The gas flowline was backfilled with clay soil at approximate 50-80 cm in thickness. Analysis showed the coal was sub-bituminous type with total sulfur content of 0.22%-1.59%. Soils with these ranges of sulfur and volatile matter have a tendency to spontaneously combust. A suspected coating burn was found at the 4 to 8 o'clock position at the failure site.