This paper first reviews laboratory and field investigations of top-of-line corrosion. A particular oxygen contaminated, wet gathering pipeline is described which experienced severe corrosion in the vapor zone. Pigging could not be accomplished, therefore a corrosion inhibitor with oxygen tolerance and vapor space capability was applied. Corrosion in the line was subsequently monitored with coupons, ultrasonic thickness measurements and periodic visual inspection. Corrosion inhibitor was detected in gas samples pulled from the line. All indicators pointed to adequate corrosion control in this pipeline even though operated in the same regime as before.
The subject of top of line corrosion damage in wet gas gathering pipelines has received attention for several years. Some of the facets of the problem seem to be condensing conditions1, acid gas presence 2,3, methanol, 4 presence of volatile organic acids1,5 and oxygen contamination 3,4. The pipeline in this study contained all of these factors. Wet, sour gas gathering pipelines are usually treated with corrosion inhibitor both by continuous treatment for control in bulk water and by batches ahead of pigs for control in the upper quadrants.6,7. Many pipelines which have been in service for several years have no provision for pigging. For these cases, corrosion inhibitors which access the vapor space have been developed. 3,8 The pipeline in this study conducted an average of 30 mmscfd (850,000 m3d) containing 1.3% CO 2 and 0.5% H2S through a 12 inch (305mm) line 10 miles(16km) long constructed of API 5L x 52 steel. Pressure averaged 720 psi (4.96 mPa). A portion of the line was periodically treated with methanol, so oxygen and methanol were both a concern since the solubility of oxygen in methanol is several times that in water. 4,9. All of the gas sources in the area contained volatile organic acids, so this factor was likely superimposed on the rest. 10,11 In most gas pipelines, the most severe corrosion occurs at the bottom of the line. In cases where flow regimes or dewing conditions place water in the upper gradients, this condition must be addressed. The presence of oxygen always makes corrosion control more difficult. 12,13
Most top of line corrosion in this gathering system had been experienced a few hundred feet downstream from compress or stations, probably because these locations experienced the most severe dewing conditions. Therefore, corrosion monitoring was concentrated in this area. Monitoring was by direct measurement, flush coupons mounted at top/sides/bottom of the line in a spool piece and periodic ultrasonic thickness measurements in the spool piece. Corrosion inhibitors were added at the basic injection rate of 1 pint per mmscfd (0.5L per 28,300m3 ) per day. Because the corrosion inhibitor should account for steel area, not just gas rate, the amount was adjusted for pipe size and length to 1 quart per mmscfd (1L per 28,300m3) per day. A few weeks after application of the new inhibitor, dry gas samples were taken from the line. These samples were analyzed by a derivitization gas chromatography procedure.