The Effects of Key Operating Conditions and Water Chemistry on Predicted Flowline Corrosion Rates

The potential for corrosion of oil and gas production systems is dependent on several different fluid parameters, e.g. carbon dioxide, bicarbonate, organic acids, amongst others. In addition, the operating conditions, which can vary through the project life, affect the estimated corrosion rate and need to be understood by the project team, so that corrosion predictions with some accuracy over the field life are reliably calculated. This paper presents three corrosion studies on subsea production flowline systems from three different offshore sample fields at the design stage. The effects of the key operating conditions (temperature and flowrates) and water chemistry (bicarbonate content, organic acid content, and H₂S and CO₂ partial pressure) on the predicted corrosion rates are discussed. Both mechanistically based corrosion model and empirical models have been used. It has been found that the corrosion rates can be relatively high when both CO₂ partial pressure, above 448 kPa (65 psi) and water production rate, above 1,590 m³/d (10,000 BPD) are at such high levels for a multiphase flowline system. In such cases, a carbon steel flowline solution is too risky, even when applying a corrosion inhibition system, thus a CRA clad flowline is usually recommended. For a gas production flowline system containing organic acids and CO₂, a potential solution is to inject pH buffer (e.g. bicarbonate), in addition to traditional film forming inhibitors.