Numerical and Experimental Investigation of CO2 Corrosion

Internal corrosion is a common problem in pipelines transporting oil and gas containing corrosive components such as CO2 and H2S. In many mature oil wells, the water cut and CO2 content may reach high level which forms a suitable environment for initiation and growth of corrosion.
To avoid the consequences of corrosion, process parameters should always be controlled within safe operating limits. To do so, corrosion rates at various values of the parameters are to be predicted to set the critical values of every parameter; and then the process should be operated below these critical values.
Efforts have been made to predict and control corrosion in many oil fields worldwide. As a result, many models and measurement techniques have been proposed. One of these models is NORSOK Norwegian standard CO2 prediction model (NORSOK 2005), which predict the corrosion rate due to presence of CO2 in straight pipes that transport single phase or two-phase (oil-water) fluids. The model is a set of three equations for prediction of corrosion rate in straight pipe within temperature range of 5-150 oC. The effects of pH is introduced to the equations as a factor calculated at different temperatures and within different pH ranges using simple empirical
Paper No.
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equations. The effect of CO2 partial pressure is introduced to the model as CO2 fugacity, which is calculated using a simple empirical equation.
In this paper, CO2 corrosion rates at different conditions has been studied using NORSOK model after modifying it to adopt for elbows geometry. The results have then been validated against values measured from a flow loop using electrochemical noise measurement (ENM). The predicted corrosion rate fairly agreed with the measured values.
Introduction