Abstract
In the steam-assisted gravity drainage (SAGD) process, casing gas from the producers consists of a mixture of produced gas and carry-over steam. The produced gas contains approximately 15% CO2 and 0.6% H2S with temperatures up to 1800C. For the corrosivity of casing gas, CO2 corrosion modelling predicts a corrosion rate (CR) of 600 mpy (15 mm/y). Mackinawite corrosion modelling predicts a rate of 270 mpy (6.75 mm/y). The results from both corrosion models predicts that the casing gas should be severely corrosive under these conditions. However, results from corrosion coupon (CC) and probe monitoring in the associated pipelines indicated low to moderate general and pitting CRs at the higher temperatures with the CR increasing as the temperature was lowered. A corrosion product analysis supported that a passivation film of pyrrhotite and magnetite had formed at temperatures above 900C. Also, the more tenacious siderite is formed at temperatures higher than 900C, contributing to the corrosion protection.
The corrosion caused by the casing gas was aggravated further by the injection of inhibited methanol for freeze protection purposes. A corrosion mitigation program was implemented that included regular pigging, the application of a corrosion inhibitor, a corrosion mechanism study, CR monitoring and a non-destructive examination program. The program was effective in reducing the CR and the operational reliability of the pipeline was maintained.
This paper discusses a proposed passivation mechanism that explains the lower than expected corrosion rates based upon the research results of peers. It also details the additional corrosion mitigation program that effectively reduced corrosion to acceptable rates.
