Disbonded Coating Leads to Pipeline Corrosion

Extensive corrosion was discovered on coal tar enamel-coated pipe on the downstream side of compressor stations. The problem was disbonded coating that prevented cathodic protection from reaching the pipe surface. Disbonding was attributed to the high temperature of the pipe and to pipe vibration from the flowing gas. It was suggested that enamel coating be replaced with a three-layer polyethylene coating in the future.

Sui Northern Gas Pipelines Co., Ltd. (SNGPL) supplies natural gas to central and northeastern Pakistan through a sophisticated and elaborate pipeline network. The company has a good safety record and has experienced only a few pipeline incidents.

Background

Corrosion problems in pipelines downstream (D/S) of compressor stations have occurred since commissioning of the compressor stations on our transmission lines. During past investigations, temperature effects on thepipelines were not considered. Of great concern was the failure of enamel coatings D/S of the Shorkot compressor station (AC-7), where a 1 6 -in (406-mm) diameter line ruptured in November 1983. Stresscorrosion cracking (SCC) caused the rupture.1 Thereafter, a number of over-theline surveys were made on thepipelines, such as C -S c an, Pearson, and on /off potential. In 2006, an external corrosion direct assessment (ECDA) was made. The results of the various tests indicated that pipe-to-soil (P /S) potentials were within the protected range per criterion.

Three pipelines are D/S of AC-7 in the same right of way (ROVV. The older two pipelines (a 24-in [61 0-mm] diameter main pipeline and an 18-in [457-mm] diameter loop line) are coated with coal tar enamel that was applied by a line traveling machine. The third pipeline (a 24-in diameter loop line) is coated with mill-applied, three-layer polyethylene (3LPE). Heat-shrink sleeves were used on the field joints.

Extensive coating failure and external corrosion were found on the 24-in diameter main pipeline and the 18-in diameter loop line. There was disbonded coating on both pipelines along with severe external corrosionunder it; this required replacement of some pipeline sections. The first 7-mile (1 1.2-km) section of the 24-in diameter main pipeline was severely pitted, requiring replacement of -7,300 ft (2,230 m) of the pipe and installation of 257 steel sleeves. The 1 8-in diameter loop line experienced corrosion in the first 3-mile (4.8-km) section, leading to a replacement of 1,500 ft (457 m), just D/S of the compressor station. Sixteen steel sleeves were installed at other locations where pitting was observed. A 7-mile section of the 1 8-in diameter loop line was recoated with coal tar.

Case Study

In this case study, we selected a 5-mile (8-km) length of the 1 8-in diameter line upstream (U/S) of AC-7 as Segment 1 and a 5-mile length of 1 8-in diameter line D/S of AC-7 as Segment 2. This line was laid in 1988. We made a comparative study to ascertain the factors that caused the coating failure and corrosion on the D/S side but not on the U/S side.

The following factors were considered in comparing both segments:

• Material
• Year of construction
• Coating
• Background information and cathodic protection (CP) statu
• Coating materials/surveys
• Soil behavior
• Temperature effects
• Microbiologically influenced corrosion (MIC)
• Polarization effects (on/off P/S potential [PSP])
• Effect of flow-induced vibration on the pipeline.

Direct Inspection

The segments of the 18-in diameter loop line being studied were under adequate CP according to the PSP data. During direct inspection of the pipe D/S of AC-7, it was observed that a bare portion exposed to the soil remained protected because it received CP. Another portion under the disbonded coating, and thus cathodically shielded, exhibited heavy pitting of up to 0.04 in (1 mm) on the pipe surface.

Although the PSP survey data had shown good results at the standard current requirement, something faulty beneath the coating was suspected. Direct inspection in 1999 to 2000 revealed that heavy pitting had occurred because the disbonded coating shielded the pipe from CP. The resultant corrosion led to pipe replacement in some portions and recoating work in others.

Direct Current Voltage Gradient

We know of no aboveground coating survey technique that can detect pitting, scaling, and other corrosionunder disbonded coating. The direct current voltage grathent (DCVG) survey works on the principle of a voltage grathent formed at coating defects. A coating defect allows CP current to reach the pipe surface, but when the pipe surface is shielded, no coating survey technique can detect a coatmg fault as no soil-to-pipe contact is formed and hence no grathent exists.

DCVG surveys were performed on the pipe U/S and D/S of AC-7 to compare coating conditions. a Although DCVG surveys will not locate disbonded coating, they will locate holidays or cracks in the coating. Previous inspections had shown that considerable coating damage existed at locations where disbonded coating was found. We conducted the DCVG surveys to see if there was any difference in the coating condition on either side of AC-7.

Only 12 coating faults were found on the U/S pipe, of which four were in die 15 to 25% range. These were later found and repaired after the pipeline inspection. There was some rust on the spiral weld of the pipeline, but no metal loss was observed.

On the D/S pipe, 141 faults were found, of which nine were in the 15 to 42% range. These areas were opened for direct inspection and repair. This section had been recoated in 200 1.

The 5-mile segment of the D/S line that was inspected has been recoated, but no recoating has been done further downstream. We made direct inspections at three locations in this area, which revealed that pitting and rust formation has started. Pit depths of up to 0.04 in were measured. Pits of greater depths may exist at some spots, which are not detectable because of shielding effects.

Temperature Effects

Soil and pipe temperatures on either side of AC-7 were recorded. Temperatures on the U/S side were ~89 °F (31.7 °C), and those on the D/S side were ~ 100 °F (37.8 °C). Temperature not only affects the coating, but also the soil around it, and leads to changes in soil resistivity.

Discharge gas is cooled by the discharge gas cooling (DGC) system. The DGC system does not operate all the time; it is shut down from time to time for maintenance or if a malfunction occurs.

Whenever a shutdown cycle of the DGC system occurs, the temperature of the D/S pipes rises to 135 to 140 0F (57 to 60 0C), which affects the coating as well as the pipe for up to 1 0 to 15 miles (1 7 to 24 km). During this cycle, coated pipe expands and contracts as does the coating, but they do this at different rates. With continuous up-and-down temperature cycles, a gap occurs between the pipe and coating. This gap may be in microns, but it shields CP current from reaching the pipe surface.

Soil Conditions

Thirteen soil samples were collected, six from U/S and seven from D/S of AC7. The samples were obtained from the ROW and at pipe depth. Some of the chemical and physical properties, respectively. These soils vary in their pH and corrosiveness. The resistivity of the soil samples, as a function of moisture content through saturation, was also characterized.

The soil in the vicinity of the AG-7 site is mainly clayish in character with a reasonably high content of carbonates and bicarbonates. The pH values indicate that the soil is alkaline.

Microbiologically Influenced Corrosion

We found no sign of sulfate-reducing bacteria or other forms of MIC during direct inspection or the soil study.

Effect of Flow-Induced Vibration on Pipeline

The flow of natural gas through the pipelines generates flow-induced vibration. Usually, flow rates in excess of 40 ft/s (12.2 m/s) create turbulence and cause vibration. This vibration causes lateral movement of the pipe on a microscopic scale, leading to disbondment of the coating from the pipe surface as the coating adheres to the soil.

Conclusions

In this investigation, we discovered that the extensive corrosion on the D/S pipe at AC-7 was caused by a disbonded coating that prevented CP from reaching the pipe surface. Disbonding is attributed to the high temperature of the pipe and to pipe vibration from the flowing gas.

We have suggested that enamelcoated pipe be replaced with 3LPE-coated pipe in the future, especially on the D/S of compressor stations. Shutdown of the DGC system should not be allowed when compressor stations are in operation.

Sumber : Waheed, Javed Iqbal. "Disbonded Coating Leads to Pipeline Corrosion". 28 Januari 2014. http://search.proquest.com/docview/759189836?accountid=31562