|Publisher||Offshore Technology Conference||Language||English|
|Content Type||Conference Paper|
|Title||Special Session - Understanding the Impact of Completion Brine Packer Fluids on Cracking Susceptibility of CRA Materials for Deepwater Applications|
Paul H. Javora, Mingjie Ke, and Richard Stevens & Qi Qu, BJ Services Company
Offshore Technology Conference, 5-8 May 2008, Houston, Texas, USA
2008. Offshore Technology Conference
|1.5.4 Completion Equipment
1.7 Fundamental Research in Drilling & Completions
5.1.1 Tubing and Casing Design
5.5.3 Chemical Treatments
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.
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
|File Size||297 KB||6|