Abstract

Seawater and/or brine injection for oil recovery is frequently accompanied by souring because such water contains sulfate mainly sourced by the growth of sulfate-reducing bacteria (SRB). The mechanisms of reservoir souring vary depending on reservoir conditions such as species of SRB, organic substances that become nutrients for SRB and temperature at what different specie can survive.The purpose of this study is to predict the reservoir souring in an oilfield in which brine injection is planned. For this purpose, chemical and microbiological analyses of the oilfield brine, kinetic studies of the growth of SRB indigenous to the brine, and numerical simulation studies on the reservoir souring in the oilfield have been performed.

Several kinds of organic substances as carbon donors that can be nutrients for SRB were found in both production and injection brine collected in the oilfield. Desulfonosporus sp., Desulfobulbus propionicus and Desulfomicrobium thermophilum were the types of SRB that were found in both brine samples by genetic analyses of DNA extracted from them. Bacterial cell number of SRB in the injection brine was ten times larger than that in the production brine. In addition, the most active growth of SRB was found in the injection brine supplemented with ethanol, therefore, the SRB inhabiting the injection brine was assumed to grow dominantly and generate hydrogen sulfide using sulfate and ethanol in the reservoir. On the basis of this mechanism, an equation that calculated growth rate of the SRB was derived with three variables: temperature, concentration of sulfate, and concentration of ethanol from the results of incubation experiments using the injection brine.

A numerical simulator including the growth rate equation for the SRB was constructed by modifying a simulator of Microbial enhanced oil recovery. The SRB grew and generated hydrogen sulfide around the injection well where temperature was decreased to <50 °C by injected brine. The results of the numerical simulation suggested that severe reservoir souring doesn't occur by the brine injection in the oilfield. Furthermore, the numerical simulation suggested that SRB generates H2S only around the injection well because of a temperature drop there, therefore, the reservoir souring can be prevented more surely by heating up the injection brine to 50 °C, or reducing ethanol in the injection water.

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