Reservoir souring commonly occurs in oilfields after waterflooding for secondary oil recovery. This is due to the activity of sulfate reducing bacteria (SRB) in the reservoir, which use nutrients from formation and/or injected water to generate sulfide.

Conventional bactericide treatments may exert limited SRB control downhole. An alternative is the use of nitrate, encouraging the growth of nitrate utilizing bacteria to inhibit sulfide production by SRB.

Laboratory tests were undertaken to determine the optimum nitrate treatment regime for a fractured chalk reservoir, including investigations into the potential for damaging effects such as corrosion, formation impairment, biofouling and solids removal or re-deposition. Upon completion of these tests, nitrate was dosed into the injection water on the Skjold field in the Danish sector of the North Sea. In one well pair with a short breakthrough time a reduction in HzS production of some 80 % was achieved. However, in less fractured regions with longer breakthrough times, the reduction in HzS concentration in the production was much less pronounced.

The Skjold oilfield is located in the Danish Sector of the North Sea and is operated by Maersk Oil and Gas AS. Production of oil and gas commenced in 1982. Two wellhead platforms are installed in the Skjold field but control and operation are conducted from the nearby Gorm Platform where the Skjold production is processed. Water injection (primarily seawater), to maintain reservoir pressure, was commenced in 1985. The producing horizon is Maastrichtian Age Chalk.

Skjold is a dome shaped chalk reservoir with a low matrix permeability of<1 mD (<10 -9 m 2) and a high, but variable, degree of naturally occurring fractures. The reservoir temperature and pressure are typically 80°C and 3100 psi (21.4 MPa). The field is completed with 20 producers and 8 water injectors. All injection wells, except one, are completed in the water zone but, due to the fractured nature of the reservoir, injection water breakthrough times can be very short. In particular, the water injector Skjold-7 is connected, via fractures, to the producer Skjold-12 and the transit time between the injector and the producer, is only a few hours.

The first recorded H2S production was in September 1985, following the start-up of water injection in April 1985 with Skjold-2 showing 1.8 ppm HzS in the gas phase. Seawater breakthrough occurred 1991 and the HzS production has increased steadily since that time. Presently, the wellhead H2S concentration in the produced gas varies between 10 ppm and 1000 ppm.

] Produced H2S data are expressed in terms of total kg/day in all three phases rather than ppm in the gas phase, avoiding misleading patterns due to changing ratios between gas, liftgas, oil and water. The HzS concentration in the gas phase is measured using Drgger tubes. The H2S concentrations in the liquid phases are then calculated using a PVT simulator. The total HzS production is calculated based on mass flow rates from well tests. Figure 1 shows that the produced HzS mass flow increased from 100 kg/day in 1994 to the present level of 700 kg/day. However, fluctuations in the HzS production pattern have been observed with a maximum HzS production of 1150 kg/day in late 1999. A

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