Sweet (CO2) and sour (H2S) corrosion have continuously been a challenge in oil and gas production and transportation. Yet, some key issues are still not well understood, especially at high temperature production conditions. A CO2/H2S ratio of 500, which has been used (often inaccurately) to determine which corrosion mechanism is dominant, is probably even less valid at high temperature. The nature of the corrosion products forming at high temperature in CO2/H2S environments and their effects on the corrosion rate are not known. Finally, the impact on pipeline integrity of environmental changes between sweet and sour production conditions (simulating reservoir souring) has not been well documented. CO2, H2S, and CO2/H2S corrosion experiments were conducted at 120oC to investigate corrosion mechanisms and corrosion product layer formation at high temperature. The results show that the corrosion products were still clearly dominated by H2S under the pCO2/pH2S ratio of 550. Formation of Fe3O4, FeCO3, and FeS corrosion product layers had a direct impact on the measured corrosion rates and was dependent on the gas composition and on the sequence of exposure (CO2 then H2S and vice versa). Compared with H2S corrosion alone, the presence of CO2 could retard Fe3O4 formation in CO2/H2S mixture environment. No obvious change in steady state corrosion rate was observed when the corrosion environment was switched from CO2 to H2S and vice versa. 

Steel pipelines are sometimes subjected to demanding sour environments resulting from the presence of high H2S contents. Pipeline materials, therefore, must be resilient against sulfide stress cracking (SSC) which is caused by H2S. Beginning in the 1980s, thermo-mechanically controlled processed (TMCP) steels have been widely used for the manufacturing of large-diameter sour service pipelines. The failure of the Kashagan pipelines in 2013 raised concern regarding the use of TMCP steels in sour environments. These concerns arise from the potential for local hard zones (LHZs) to be produced on the surface of the line pipe during TMCP processes, ultimately leading to through-wall SSC failures. In the present study, several X60 - X65 TMCP steels (both with and without LHZs) have been tested under different Region 3 (R3) conditions in the NACE MR0175/ISO15156-2 pH-H2S partial pressure diagram. It can be concluded that the presence of LHZs increases TMCP steels’ sour cracking susceptibility; however, TMCP steels without LHZs pass the SSC tests at even the most severe R3 environments. Traditional HRC or HV10 testing are not able to detect LHZs, and so lower load HV 0.5 or HV 0.1 tests are necessary. For TMCP steels, the current R3 may be further divided into R3-a and R3-b sub-regions. The sour cracking severity of R3-a is less than that of R3-b. Additional actions, like enhanced mill qualification of the TMCP plate, should be considered to ensure that no LHZs exist in steels to be utilized in R3-b environments.  

There are three known types of high temperature sulfidation present in the refining industry. Two of them have industry recognized methodologies for damage prediction, and they both manifest as general thinning morphologies. They are known as H2-free sulfidation and H2/H2S corrosion. The third type, although recognized as H2-free, low-sulfur corrosion, does not have an accepted chemical theory or a prediction tool, and it manifests as a localized thinning morphology. This third type of sulfidation is much less common and occurs in units and process conditions where little-to-no H2S would be expected to be present. This paper discusses the operating conditions in two known damage cases presented here and provides a viable chemical theory that could lead to the observed damage profile. In addition, an approach to mitigation of this attack is discussed.