An Analytical Model for the Corrosion Risk of Water Alternating Gas Injection Wells in CO₂ Enhanced Oil Recovery

Abstract

An analytical model is proposed to describe the corrosion risk profile of a well tube in water alternating gas (WAG) CO 2 injection conditions based on the assumption that the drying process of the water layer on the inner wall of the well tube plays a crucial role in controlling corrosion. In this model, the fluid properties, the thermodynamic equilibrium of CO 2 and water steam, and an empirical CO 2 corrosion equation are systematically considered. The description by this model reasonably indicates that fast injection can decrease the corrosion risk and push the highest risk region to a deeper zone, while a longer drying time for a thicker water layer left on the well inner wall can lead to higher corrosion risk. It can also be deduced that the offshore WAG case is more aggressive than the onshore case and some mitigation strategies are suggested for reducing the corrosion risk. These should be helpful for corrosion management and leakage monitoring in the practical WAG CO 2 injection.

Corrosion Control in CO2 Enhanced Oil Recovery From a Perspective of Multiphase Fluids

“…CO 2 injection may need a pressure higher than 10 MPa at wellhead and the pressure will be further increased with depth from wellhead. As reported in a previous paper (Wang and Song, 2018), at a depth of 3,000 m, the pressure can be higher than 35 MPa, which is certainly determined by the injection rate and the pressure at wellhead. Temperature is closely relied on the depth profile of the ground temperature.…”

“…Corrosion inhibitors Process control CO 2 transportation Mild steel (e.g., 16 Mn) Effective in highly acidified, high pressure and high temperature conditions. (e.g., Xiang et al, 2017) Controlling impurity gases (de Visser et al, 2008;Sim et al, 2014b) Limiting water concentration (Sim et al, 2014b) Slowing down flow and pressurizing (Liu et al, 2018) CO 2 injection Mild steel (N80, P110) Stainless steel (304SS, 13Cr) Coatings or liners (IEAGHG, 2010) Injected with water slugs Reducing water/gas alternate frequency (Wang and Song, 2018) Oil production Mild steel (N80, P110) Stainless steels (304SS, 13Cr)…”

“…During the WAG injection process, corrosion occurs when the CO 2 slug begins to drive down the previous water slug, leaving a water layer on the pipe inner wall being acidified by flowing CO 2 . Recently, Wang and Song theoretically evaluated the corrosion risk of steel materials in such WAG conditions by assuming that the steel surfaces were periodically exposed to the wet/dry cycles in CO 2 fluids and the corrosion was dependent on the dissolution of CO 2 in the water layer (Wang and Song, 2018). In their simulation work, the time of forming a CO 2 saturated water layer was simiply determined by the diffusion rate of CO 2 through the layer, which was assumed to be very fast and genrally less than several minutes (Grogan et al, 1988;Farajzadeh et al, 2009), having little influence on the overall corrosion performace.…”

“…Nevertheless, limiting water concentration is still the best choice for corrosion mitigation in CO 2 transportation (Sim et al, 2014b;Barker et al, 2017). It can be deduced from the experimental simulation that pressurizing CO 2 could extend the solubility of water (Wang and Song, 2018) and thus reduce the possibility of water wetting on steel surface. Slowing down the flow rate may reduce the probability of the bombardment of water clusters entrained in dense phase CO 2 ,…”

“…In this way, transporting water containing CO 2 at a high pressure and with a slow rate may be helpful for corrosion mitigation. In a WAG CO 2 injection process, reducing the alternate frequency and increasing the injection rate can extend the service lifetime of well tube (Wang and Song, 2018). Obviously, tailoring the processing parameters in CO 2 transportation and injection should be cautious as the environmental variation may totally change the control strategies.…”