Effect of CO2 and salinity on microbial hydrogen sulphide generation in hydrocarbon reservoirs

Abstract

This work investigates the effects of CO2 and salinity on the biosouring process in hydrocarbon reservoirs that is applicable in carbonated low salinity or smart water injection projects. Biosouring refers to the generation of hydrogen sulphide gas in oil reservoirs due to the activity of sulphate reducing bacteria (SRB). The influence of key parameters including pH (that is affected by CO2 concentration), temperature, and salinity on the microbial activity of SRB is studied using a Buckley-Leverett based flow model linked to PHREEQC geochemistry software. Simulation results are validated against some experimental data taken from the literature. The simulations are performed at varying pH (6.0–7.0), temperature (40–100 °F), and salinity (0.5–0.8 meq/ml) of NaCl to assess their effects on the souring process. Additionally, two models are developed applying the response surface method to relate the concentration of hydrogen sulphide and souring onset to pH, temperature, and salinity. The results suggest that the souring onset delays when the reservoir pH decreases (pH ≤ 6.0) and injection temperature and salinity increase. Moreover, higher values of pH result in an early onset if the temperature is kept low (40–60 °F). The findings also indicate that temperature and salinity affect the H2S concentration. The highest H2S concentrations are observed when the temperature is ranged between 40 °F and 70 °F if salinity is kept in the range of 0.5–0.65 meq/ml. Moreover, for a pH value in the range of 6.8–7 and when the temperatures are between 40 °F and 70 °F, a higher volume of H2S is generated. The findings of this research help to manage the microbial souring issue in oil fields through controlling influential parameters achievable via carbonated smart water injection.