Simulation of reservoir souring has been a neglected area of corrosion research. The procedure followed herein is to form a sweet corrosion product layer, introduce a low concentration of H2S in the gas phase (<100ppm) and allow the system to continue to evolve. The experimental apparatus used was a 2L glass cell with an impeller in the center and 5 samples spaced evenly around it to allow for in situ corrosion rate monitoring and extraction of specimens for surface analysis. In experiments involving Fe3C residues the general corrosion rate decreased when H2S was added to the system. FeS was detected on the samples with the Fe3C; it is postulated that a thin layer of FeS forms leading to the decrease in general corrosion rate. When the FeCO3 was challenged with H2S, the general corrosion rate increased. FeS was detected on the samples, but no significant change was observed in the FeCO3. However, it was electrochemically determined that the H2S impacted the FeCO3 sufficiently to allow the general corrosion rate to increase.
A 2002 study estimated the annual cost associated with corrosion of gas pipelines to be around $5 billion.1 Corrosion of oil and gas pipelines continues to pose a major issue in the oil and gas industry due to the combination of brine produced with the oil and the type of acid gas present which can lead to significant internal corrosion. Oil and gas reservoirs can be separated into two categories, sweet and sour. In sweet reservoirs carbon dioxide (CO2) is the dominant gas species that dissolves in the brine and hydrates to form carbonic acid which can increase the corrosion rate through a buffering effect but can also dissociate to react with ferrous ions to form corrosion product layers containing iron carbonate in the iron carbide matrix of the mild steel pipeline material. In sour reservoirs hydrogen sulfide (H2S) is the dominant corrosive gas species, which similarly will dissolve in the brine and react with ferrous ions to form iron sulfide corrosion product layers associated with its presence, such as mackinawite. Understanding the characteristics of a reservoir is essential when planning how to appropriately mitigate the corrosion that may occur, which includes material selection, inhibitor selection, and many other strategies. However, if a reservoir changes from sweet to sour, this can cause a large problem as the strategies previously selected and implemented may no longer be sufficient to control the corrosion. When H2S begins to appear in a previously sweet reservoir, this is a phenomenon commonly known as souring. This can come about from a variety of pathways, the two most common being souring due to the presence of sulfate reducing bacteria (SRB) being unintentionally injected into the reservoir which then begin to produce H2S. It is also possible that the SRB may already be present in the reservoir, but the injection water used may contain a high concentration of sulfate which then leads to the formation of H2S. Regardless of how the reservoir begins to sour, it is important to understand what changes may occur once the souring has begun.
