Abstract
It is very common for oil and gas production facilities to observe an increase in H2S concentration with time due to reservoir souring. In these cases, it is critical to assess if all materials in contact with the fluids are fit for sour service and to determine critical H2S concentrations above which specific materials may be susceptible to sulfide stress cracking at different operating conditions. This paper summarizes the work performed to assess sulfide stress cracking susceptibility (SSC) of selected topside (e.g., slug catcher, separators, coolers, compressors) and subsea (e.g., manifold, lines) facilities based on data collected topsides.
Based on the fluid chemical composition measured at several sampling locations topside and operating conditions (pressure, temperature, oil, water and gas flow rates), the H2S concentration and fugacity, pH and dew point were calculated for selected streams of the topside and subsea systems using a predictive thermodynamic model. These results were then used to evaluate the severity of each stream with respect to SSC of carbon steels or low alloy steels according to NACE MR0175/ISO 15156. Simulation results showed that the commonly used approach of assuming the H2S concentration measured topsides to calculate the partial pressure subsea may be too conservative, overestimating the H2S partial pressure up to 3 times in the cases evaluated. The use of fugacity in lieu of partial pressures in determining SSC susceptibility was also addressed.
