Oil and gas production fluids normally contain CO2 gas and often H2S. These gases dissolve in water, lower the pH and potentially result in severe degradation of carbon steel. When sufficient H2S is present in the produced fluids it dominates the corrosion behaviour and the conditions are defined as sour. Sour corrosion is dominated by scale formation and high local corrosion rates due to scale disruption. Sour conditions may also introduce cracking of materials, which is not part of the scope of this paper. Most practical sour corrosion models (including our previous in-house sour corrosion model) used for corrosion engineering are developed based on CO2 corrosion fundamentals. The current models are often conservative for sour corrosion, but sometimes also under-predict corrosion rates.
To come up with an improved sour corrosion model, a new model was developed based on:
The corrosion mechanisms and associated corrosion rates were obtained from and calibrated with field experience, literature and laboratory testing. All data was captured in a database. As part of the validation, the results of the new model were compared against the data in the database and the old corrosion model. The improved prediction resulted in a significant reduction in conservatism, especially for conditions with an elevated temperature, without deposits and at a low salinity. To improve the effective use of the model and to guide engineers in addition to corrosion prediction, specific corrosion mitigation measures required for sour corrosion were incorporated.
Oil and gas production fluids normally contain CO2 gas and often H2S gas. These gases dissolve in water, lower the pH, and potentially result in severe materials degradation. When sufficient H2S is present in the produced fluids it dominates the corrosion behaviour and the conditions are defined as sour.