Corrosion remains a key obstacle to sustaining operational success in hydrocarbon production. Its continued occurrence affects the economy and has consequences for the safety of people and integrity of facilities. A central element in the design of facilities and corrosion mitigation is the correct choice and deployment of materials which are both economical and suitable to provide satisfactory performance over the design life. This paper captures the current understanding of corrosion mechanisms in the combined presence of H2S and CO2 acidic gases and discusses a systematic approach to materials design strategy for hydrocarbon production systems. The paper does not deal with the important environmental cracking aspects associated with sour service, but rather concentrates purely on metal loss degradation process. The combination of H2S and CO2 modifies the corrosion characteristics significantly as compared to damage caused in the sole presence of CO2 or H2S. An H2S/CO2 ratio is introduced to indicate the trends governing corrosion mechanism, i.e. dominated by CO2, H2S or a mixed mode of damage. A simple guideline has been produced offering a rule of thumb in addressing respective corrosion damages.


Corrosion in hydrocarbon systems manifests itself in several forms amongst which CO2 corrosion (sweet corrosion), H2S corrosion (sour corrosion) in the production systems and oxygen corrosion in water injection systems are by far the most prevalent forms of attack. The environmental sensitive cracking damage caused by H2S and consequent materials optimisation are other very important aspects in these systems, but these are already covered in detail elsewhere. Corrosion in water injection systems is also outside the scope of the present overview. An additional key element affecting corrosion is the presence of elemental sulfur in the production stream, which is again beyond the scope of the present paper. The majority of oilfield failures result from CO2 corrosion of carbon and low alloy steels (CLASs), primarily due to inadequate knowledge/predictive capability and the poor resistance of carbon steels to this type of attack. Its understanding, prediction and control are key challenges to sound facilities design, operation and subsequent integrity assurance. Extensive research over the past five decades has focused on the mechanistic and engineering understanding of CO2 corrosion of CLASs, with a view to develop a realistic model to predict its occurrence. These are broadly covered in a review elsewhere. Despite this, the majority of existing quantitative models remain unreliable in predicting the actual long-term CO2 corrosion rate of CLASs. The anomalies are attributed to "field artefacts" with no clear indication of the cause. One key cause of the difference is now attributed to the effects of organic acid a chemical normally ignored by many. An added complication is the presence of H2S which in turn affects potential corrosivity, insitu pH and interferes with the formation of corrosion product. This review article captures the current understanding and means of dealing with H2S in CO2 corrosion evaluations for CLASs in hydrocarbon production. It provides information on the mechanisms, highlights key parameters affecting the complementary influence of the two acid gases and draws attention to areas requiring further research. The primary focus has been placed on two key parameters affecting CO2 corrosion in the presence of H2S including (i) the nature of the surface film and (ii) development of an engineering guide for dealing with the risk of H2S-CO2 corrosion in production conditions. A brief overview of the specific material choice route for different production areas is prov

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