This paper addresses frequent failures of natural gas transmission pipelines in one of the Iranian gas production fields. The three phase flowing fluid consists of 0.15 to 0.384 mole fraction of carbon dioxide with an average of 9 bbl/mmscf water cut. The material of 10-in flow lines are API 5L X65. Internal corrosion is mitigated by means of amine type corrosion inhibitor (CI). The fluid corrosivity, optimum concentration and injection rate of CI determined by means of polarization electrochemical tests and field data. Internal corrosion monitoring tools are including of weight loss corrosion coupons, electrical resistance(ER) probes and Iron counting in compliance with NACE standards. The occurred destructions differ in low and high off take gas wells. Having finished the pipeline construction, the free water left in some pipelines from hydrostatic test (a gap between hydrostatic test and pipeline operation) accelerated the initiation of corrosion process. During pipeline operation, the dissolved oxygen in diluted CI helps merging electrochemical cells under the deposits and this led to pitting corrosion. Generally, the deposit compositions are including Magnetite, Hematite, Wustite, Iron carbonate and Calcium carbonate. For high off take gas wells, erosion/corrosion phenomena observed in wellhead facilities. In such wells, the uniform corrosion is a consequence of deposit removing by higher velocity of the fluid. An intelligent pigging MFL was performed in one of the damaged flow lines in order to estimate the dimension of corrosion damages. Immediate actions are foam cleaning (chemical washing) to remove the deposits on the pipe wall and the possibility of using oxygen scavenger in the chemical injection packages in order to alleviate dissolved oxygen in Diluted CI.


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