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 CaCl2 brines have been linked to ingress of acidic gas containing CO2 and H2S 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 (CO2+H2S). 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.