Corrosion Rate Prediction in the Liquid Collection Section of Separating Tanks—Part 1: Dependence on Temperature, O2, pH, and Superficial Conditions

Abstract

The exploitation of oil and gas reservoirs produces oil-gas-water mixtures which are set apart in separating tanks. The main operating risk of these tanks is the presence of aggressive compounds, such as carbon dioxide (CO2) and hydrogen sulfide (H2S), which can cause corrosion in the tank wall, and in the pipes and equipment used in the downstream processes. To assess accurately the integrity of separating tanks, the prediction of the corrosion rate in their water collection section is necessary. In this work, modeling of the operating environments of separating tanks has been carried out from the results of corrosion tests performed using the polarization resistance (Rp) technique. Rp tests were conducted on a SA-516-G70 carbon steel (UNS K02700) using as a medium NACE 1D182 and NACE 1D196, two different brines, without H2S or CO2. The separate and combined effects on the corrosion rate of the corrosion product layers, and of the brine temperature, pH, and oxygen presence were investigated. After measuring the corrosion rate in each environment, mathematical models were proposed and fitted to the observed corrosion rate data. The validation of the proposed models was carried out by comparing their results with those of models reported in the literature, predictions from commercial corrosion-prediction software, and field-measured corrosion rate data.