The annular space between the production tubing and the carbon steel casing is filled with a dense fluid, typically a halide salt. In wells with corrosion resistant alloy (CRA) tubing, SCC of the CRA tubing OD or auxiliary components has occurred in a number of wells. Halide brines have densities up to 2.2 g/ml (19.2 lb/gal or ppg) and contain a number of additives.
A previous publication linked some field failures to the addition of SCN-corrosion inhibitor. [1] Additional field failures in CaCl 2 brines have been linked to ingress of acidic gas containing CO 2 and H 2 S and to exposure to air. SCC of martensitic stainless steel (SS), (13 % Cr, 6 % Ni, 2 % Mo) was attributed to downhole leakage of acidic gas [2], whereas SCC of a duplex SS tubing (25 % Cr, 3 % Mo) was attributed to air in the gas cap above column of brine. [3] To understand the effects of brine compositions on the CRAs, a joint industry project was formed under the auspices of the American Petroleum Institute (API).
It has been known as the CRAs in Brine Testing Program. Under its auspices, work has been underway for a number of years on understanding the interaction of brine chemistry and CRAs. The current paper evaluates the SCC risks of a range of CRAs in various halide brine compositions for the case of exposure to acidic production gas (CO 2 +H 2 S). Also evaluated are SCC risks due to air exposure. However, the testing became focused on a group of martensitic stainless steels alloyed with Ni and Mo, that are collectively referred to as modified 13Cr martensitic SS, or alternatively in some publications as super (S13Cr) martensitic SSs.
Most tests evaluated the as-received brine, excluding proprietary additives such as corrosion inhibitor or oxygen scavengers. For completeness and comparison, test results provided by member companies in the API program or in the publications are cited; these test protocols may be different from those in the API test protocols hence, where that occurs, significant differences are noted.
