Assessing the Magnitude and Consequences of Reservoir Souring Figure 1: Sulphate-reducing Bacteria Electron Micrograph This near injection well bore concept of reservoir souring4 is illustrated


schematically in Figure 3; again, the putative zone of H2S generation by SRB is marked in green.


An important concept is that even low concentrations (1–2 mg/l or less)


of H2S generation in the water phase can equate to tens or even hundreds of ppmv in a gas phase in equilibrium with that water, depending (mainly) on the pressure, temperature, fluid phase ratios, percentage injection water breakthrough and pH at the point at which the gas phase H2S concentration is measured (usually at a separator).


There are two reasons why the concentration of H2S in the gas phase of a soured well increases during field life and they are both


Bar = 1 µm.


Figure 2: Sulphide Generation in the Reservoir – ‘Mixing Zone’ Concept


physico-chemical effects. The first reason is that the percentage water breakthrough increases, so an increasingly greater volume of


H2S-containing water contributes to the total fluid production. The second reason is that the volume of produced gas as a proportion of produced liquid decreases with time as the water cut increases; this is because most of the volume of the gas results from


depressurisation of the oil, whereas off-gassing of dissolved H2S occurs from both oil and water – so a constantly increasing mass of


Mixing Zone (mobile)


H2S per unit volume of liquid partitions into a constantly decreasing volume of gas per unit volume of liquid, resulting in sharply


increasing gas phase H2S concentrations, without the need for any additional bacterial sulphide generation activity.


Interface Biofilm (stationary)


Figure 3: Sulphide Generation in the Reservoir – ‘Near Injection Well Bore’ Concept


Injector H2 Oil organics + SO4 2- → CO2 + H2 S


The most convincing evidence for a ‘near injection well bore’


reaches the produceer Eventually the H2 S


model of H2S generation comes from back-flow of injection wells.


Another concern about the deep reservoir mixing zone concept of reservoir souring is that many mixtures of seawater and formation water are too saline to sustain SRB growth.


The most convincing evidence for a ‘near injection well bore’ model


of H2S generation comes from back-flow of injection wells. When water injection wells supporting soured producers are back-flowed, this almost invariably results in a ‘spike’ of water


containing a population of SRB, accompanied by dissolved H2S at concentrations which can fully account for the mass balance of H2S in produced fluids.


92


a typical medium-density North Sea crude oil have been applied. There is a huge increase in H2S content of gas purely from the fluid phase partitioning effect, without any change in SRB activity. If the effect of increasing water breakthrough were to be included, the upward trend in H2S concentration in gas would be flattened in the earlier period and even sharper at the end. The data that underlie Figure 4 are presented in Table 1.


Stimulatory and Inhibitory Factors


Re-injection of produced water mixed with seawater or other sulphate-bearing water can give rise to stimulation of microbiological


EXPLORATION & PRODUCTION – VOLUME 9 ISSUE 2 S


The latter effect is very important in understanding well souring and is illustrated in Figure 4, which is a graph of calculated H2S concentration in the gas phase versus time. In this simplified


illustrated example, there is constant production of 40 mg/kg H2S by bacterial activity in the injection water. The total production is held


constant at 1,000 barrels/day but the water cut changes at a constant rate from zero to 99 % between 2015 and 2023 (arbitrary dates). We have assumed 100 % injection water breakthrough throughout the well production life, so any effect of additional H2S production is completely removed from the calculation. Partition rate constants for


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