Mitigation of Reservoir Souring by Nitrate in a Produced-Water Reinjection System in Alberta

Abstract

Abstract We report the reduction in levels of H2S in produced gas and water using nitrate treatment in an oilfield in Southern Alberta that is under produced water re-injection. Approximately 4,500 m3/day of water is injected, primarily produced water supplemented with make-up water from the outfall of a municipal waste treatment plant. The reservoir is 30–40°C. Calcium nitrate was continuously applied at 150 ppm (as nitrate) into the injection water at a central water plant and distributed to injection wells field wide. A biocide, acrolein, was also applied in weekly batches to treat the injection lines and prevent nitrate-fed biofilm accumulation. After one month of treatment, H2S in the produced gas from one gathering system dropped from an average of 170 ppmv to 110 ppmv (average 3.4 kg/day to 1.8 kg/day). This represents an approximately 50% reduction in produced H2S in the gas. A corresponding decrease in H2S in the produced water was observed. One problematic well maintained an H2S level of approximately 800 ppmv. To treat this well, a nearby injector was started on a weekly treatment of a single batch of calcium nitrate dosed to approximate 600 ppm, based on a seven-day production rate. Sulfide levels in the problem well dropped significantly and over the subsequent 18 months there has been on average <15 ppmv H2S in the produced gas. Introduction Reservoir souring is a common problem associated with water injection for secondary oil recovery (Vance and Thrasher 2005), and souring has been observed in both onshore and offshore systems. Typically, sulfate carried in the injection water is metabolized to sulfide by sulfate-reducing bacteria (SRB) that grow in the injection plume. SRB proliferate in sulfate reducing environments, i.e. environments that contain sulfate and lack other electron acceptors such as nitrate and oxygen. Nitrate provides more energy than sulfate when used as a bacterial electron acceptor and promotes the growth of a bacterial guild, nitrate-reducing bacteria (NRB), which out-competes SRB. This is why SRB are not problematic in waters containing nitrate. Injection water for secondary recovery typically does not contain nitrate. In recent years it has been increasingly common to treat souring reservoirs by continuously injecting a nitrate salt to provide the reservoir environment with nitrate as an electron acceptor (Sunde and Torsvik 2005; Telang et al. 1997). Microbial reduction of nitrate provides approximately three times more energy than does the reduction of sulfate. Therefore, in the presence of both nitrate and sulfate, NRB tend to grow faster and dominate (Jenneman et al.1986; Hitzman and Sperl 1994) and to suppress the growth of SRB by various mechanisms (Hubert et al. 2003) resulting in a gradual sweetening of the reservoir. NRB are widely distributed in oilfields around the world (Eckford and Fedorak 2002; Voordouw et al. 2007) and are usually present in injection water. Upon addition of nitrate NRB proliferate quickly and begin to dominate the microbial ecology. We describe here a nitrate application to reverse microbial reservoir souring and decrease H2S in produced gas over a period of 20 months in a field under produced water re-injection. The Glauc C field The Glauc C field is a shallow oil and gas reservoir located in southern Alberta. The field is divided into three injection zones served by separate water injection systems. The reservoir was initially sweet, but after years of produced water re-injection the level of H2S in produced gas began to rise steadily. Remedial action became necessary to reduce the H2S and calcium nitrate was chosen as a treatment.