Corrosion resistant alloy (CRA) production tubing has been used for many years to service deepwater and high-temperature high-pressure wells. Pushing the materials used for these extreme circumstances has, unfortunately, resulted in stress corrosion cracking failures in the completion fluid and packer fluid environment. Most of these failures were related to the use of high strength CRA materials with packer fluid systems containing sulfur-based corrosion inhibitors and calcium chloride-based brine. Field observations and laboratory investigations regularly widen our understanding of these factors, and factors such as fluid properties, temperature and brine additives, which can also have a significant impact on the cracking process.
The focus of this work is to define the impact that composition of the packer fluid has on the cracking susceptibility of selected chrome tubular materials, and in particular, to understand the role and impact that calcium chloride has on cracking susceptibility. Additionally, understanding the influence of representative packer fluid additives is equally an important focus. New information derived from laboratory results and data analysis is presented.
Significant results and discussion are presented to clearly identify compositional factors associated with potential oilfield cracking failures of CRA materials. The use of ‘guidelines’ to select the best completion brine packer fluid for a given chrome tubular is discussed.
For over 25 years, the oil and gas industry has successfully used calcium chloride, calcium bromide, zinc bromide brine and mixtures thereof, for well completions and packer fluids. During this time, composition of the brines had not changed significantly, except for the adaptation of historic blending formulations to prevent crystallization of brine in cold climates and to overcome the increased temperature of crystallization for most brine due to the high pressure and low temperature (~38F) at the mudline in deepwater environments. Otherwise, only the additive packages have changed significantly over the years to essentially control corrosion1 of oilfield steel. Unfortunately, many of these inhibitors recently were found to create severe problems and field failures, especially when used with high-strength chrome tubulars.2–4 To overcome these problems, new corrosion inhibitor packages have been successfully applied in the field.5, 6
One failure was reported for 13Cr(2Mo)95 [13% chrome; 2% molybdenum; 95 ksi] in an 11.0 ppg CaCl2 brine inhibited with ammonium bisulfite, a morphorline based corrosion inhibitor and glutaraldehyde used in a well with a bottom hole temperature of 300F (Resak A-6, Malaysia).2 Failure analysis concluded that the presence of oxygen, CO2 and H2S in the CaCl2 brine was the most likely cause for the cracking. Extensive laboratory evaluation demonstrated that similar SCC susceptibility could occur in CaCl2 brine by lowering the pH or not adding an inhibitor package. Comparative testing demonstrated that cracking did not occur when CaBr2 or NaBr brine environments were used.
Failure of 22Cr-130ksi in 11.0 ppg CaCl2 inhibited with ammonium bisulfite and sodium thiocyanate (NaSCN) at about 370°F (Deep Alex, Gulf of Mexico) 3 was reported and the cause of the failure was environmentally assisted cracking. Headspace gas analysis from laboratory tests designed to determine the cause for the failure, detected significant amounts of H2S and smaller amounts of CS2 and CH3SH, most likely produced by the decomposition of ammonium bisulfite and/or sodium thiocyanate. Stress corrosion cracking (SCC) due to hydrogen sulfide has been attributed to the sulfur-based inhibitors, some of which had been reported to decompose and generate hydrogen sulfide.7, 8