Hydrogen sulfide, or H2S, is caused by the breakdown of organic material within an anaerobic environment. An oilfield is typically an “anaerobic” or oxygen deprived environment because it is buried thousands of feet deep. Many oils may also contain a significant amount of sulfur within an asphalt component.


For oil reservoirs that have developed H2S gas and soured over the millions of years it developed, the H2S will already be present within the reservoir fluid. In sweet reservoirs with large amounts of sulfur present, H2S may still be generated. This can happen if injection of fluids containing sulfur consuming bacteria happens and the reservoir temperature is conducive to allow the bacteria to grow and feed on that sulfur. Their waste product becomes H2S.
In the event that water injection is planned for a sweet crude reservoir, then a fluid study needs to be undertaken to determine the possibility of reservoir sulfur being reduced to H2S. If this is the case, then the injection water must be treated with a biocide and tested for the presence of bacteria to confirm the effectiveness. Preventing the souring of a sweet crude is preferable to dealing with produced H2S; water treatment is relatively safe and inexpensive compared to processing fluids laden with hydrogen sulfide.


When a formerly sweet crude reservoir sours, this can be an enhanced hazard due to the surprise involved with the new produced hydrogen sulfide. In producing reservoirs with established hydrogen sulfide, procedures and processes are already put in place to protect workers and equipment from the toxic and corrosive gas. In the case of a souring reservoir, the producing equipment may not be rated for H2S corrosive service and the workers may not have the proper training and monitoring procedures in place to protect them because they are not expecting a sweet crude to produce H2S.

Recommended Training: H2S Monitor, San Antonio H2S Training