## 1 Introduction  
In the oil and gas industry, the severity of CO\({}_{2}\) corrosion (or sweet corrosion) of pipelines is affected by crossed reactions and the interaction of different factors, including environmental, metallurgical, and physical parameters. The main environmental variables that affect CO\({}_{2}\) corrosion are temperature, pressure, flow condition, type of material, and salt concentration. Moreover, impurities in the surrounding flow may significantly impact the corrosion of carbon steel [1, 2]. The main concern of CO\({}_{2}\) corrosion is that it may lead to equipment failure, especially in the tubing/casing of the production and injection wells, as well as pipelines, thus interrupting the oil/gas production [3, 4]. Even the slightest change in one of these parameters can considerably impact the corrosion rate, given the property changes in the thin layer of corrosion products accumulated on the surface of the steel [5,6]. When corrosion products are not on the surface of the steel, high rates of corrosion of several millimeters per year can take place. Corrosion rates can be substantially reduced under the conditions in which iron carbonate (FeCO\({}_{3}\)) can precipitate on the steel surface and create a dense and protective corrosion product film. This occurs more easily at high temperatures or high pH in the water phase [6,7]. High temperature increases the rate of reaction, which produces a protective corrosion product layer, thus reducing corrosion rates, while high pH reduces the descaling of the corrosion product layer, which yields a low corrosion rate [3,8]. Dry CO\({}_{2}\) is not corrosive under the temperatures found in oil and gas production. It must dissolve in a liquid phase to cause an electrochemical reaction between the steel and the liquid phase in contact. CO\({}_{2}\) is soluble in water and brine. However, it should be pointed out that it has a solubility rate similar to that of hydrocarbon, both in the gaseous and liquid phases. Thus, for a mixed-phase system, the presence of the hydrocarbon phase may provide CO\({}_{2}\) deposition for the partition in the liquid phase. CO\({}_{2}\) is usually found in the produced fluids. Basically, CO\({}_{2}\) corrosion is an electrochemical process consisting of several steps that occur between the corrosive species that result from CO\({}_{2}\) dissolution and the soluble phases of steel. The corrosion of tubing in a CO\({}_{2}\) environment has been widely studied under various conditions to understand its corrosion mechanism and protective methods [9-27]. Using chemical treatment to prevent iron and steel from CO\({}_{2}\) corrosion is one of the most cost-effective ways [28-30]. Organic molecules are one of the most popular, efficient, and practical corrosion inhibitors, and most studies demonstrate that organic compounds, preferentially those containing nitrogen (N), sulfur (S), and oxygen (O), have high inhibitory efficiency [31-35]. [PERSON] et al. [36] specifically compared essays on corrosion inhibitors carried out in a flow loop with a rotating cylinder. The obtained corrosion rates revealed significant differences depending on time, given that they were tested at 1 bar of CO\({}_{2}\), 50 \({}^{\circ}\)C, pH 5.6, and 20 Pa shear stress. These differences exist because of the different shear stress generated in FL and RCE tests on the surface of each tested sample. Shear stress equations for both FL and RCE tests are shown below [37-41]. \[\text{RCE }\sigma_{\text{c}}=0.079\text{ Re}^{-0.3}\text{d}\text{v}^{2} \tag{1}\]  
\[\text{FL }\sigma_{\text{p}}=0.039\text{ Re}^{-0.25}\text{d}\text{v}^{2} \tag{2}\]  
where \(\sigma_{\text{c}}=\text{turbulent shear stress (cylinder), Re = Reynolds number, d = fluid density, \(\sigma_{\text{p}}=\text{turbulent shear stress (pipe), and v = fluid velocity. }\)  
Nowadays, the efficiency of corrosion inhibitors under certain flow conditions can be assessed using RCEs in accordance with ASTM [42-44].