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Investigating the impact of extended shut-in periods on oilfield reservoir souring

Rawwater, a UK-based specialist in oilfield reservoir souring control, has completed a major study into the effect of operational shut-downs on sour gas production. The research has been conducted in association with Yara ASA. The latest findings will enable oil companies to more accurately forecast the level of microbiological souring in their reservoirs.

During operational shutdowns, significant microbiological hydrogen sulfide production (often referred to as an ‘H2S burst’) is frequently observed during the resumption of extraction, with treatment by nitrate injection being used to varying degrees of success. As souring control can run into many hundreds of millions of dollars, accurately forecasting microbiological reservoir souring and nitrate dosing is vital to ensuring the most cost-effective treatment strategy.

Rawwater pressurised bioreactor suiteThrough the use of its pressurised bioreactors, which replicate the conditions found in the reservoir, and its DynamicTVS© (Thermal Viability Shell) predictive oilfield souring modelling tool, Rawwater is a world leader in assisting operators in forecasting if, when and to what extent their oilfields will sour.

For this latest study, Rawwater took its considerable knowledge of oilfield souring a stage further, by investigating how sulfide production and nitrate reduction compared comparatively under different shut-in periods, up to a maximum duration of 32 days. The findings were then fed into the DynamicTVS© modelling software to enable oil operators to factor for shut-ins when forecasting sour gas production. For the study, 12 of Rawwater’s pressurised bioreactors, each containing sand (to mimic downhole mineralogy), seawater and a ‘light’ crude (chosen for its ability to support both microbiological sulfate and nitrate reduction under simulated conditions), were inoculated with oilfield bacteria and operated at 1,000psig/30°C/pH 8.0 – a pressure/temperature/pH combination selected to simulate the near wellbore conditions at the base of the injector, in a relatively low-pressure field. The objectives of the research were: to better understand how sulfide production and nitrate reduction compare under different shut-in periods; the effect of nitrate dosing and different shut-in periods on the distribution of microbiological population; and to determine if nitrate injection can successfully control microbial souring under extended shut-in conditions. Daily sulfide levels were compared with cumulative sulfide levels achieved through shut-in; the presence of nitrate under daily batch injection was compared to nitrate levels following shut-in.

“By utilising no fewer than 12 of our pressurised bioreactors, we were able to achieve a study period lasting a ‘combined’ total of 4,800 days – the equivalent of 13 years’ worth of pressurised bioreactor data,” comments Rawwater Senior Project Officer, Matt Streets. “After recording either stable microbiological sulphide production or nitrate reduction, the shut-in period for each of the test bioreactors was then doubled to two, four, eight, 16 and finally 32 days – durations chosen to replicate the effect of real-world injection shutdowns. Throughout the study period, the rate of microbiological sulphide production and nitrate reduction was monitored to determine the extent to which shut-in periods stimulated microbiological utilisation of sulfate and nitrate. Highly insightful, the findings have been used to further enhance the nitrate treatment calculator for DynamicTVS©.”

The research carried out by Rawwater, in association with Yara ASA, showed significant differences in the rate of sulfide production between the ‘daily’ sulfide and the shut-in sulfide groups. Significant differences in the rate of nitrate reduction between the ‘daily’ nitrate and the shut-in nitrate groups were also observed. It was also noted that longer periods of shut-in significantly decreased the diversity of the microbiological community in both the presence and absence of nitrate, and that the presence of nitrate resulted in a decreased sulfide-producing capability and an increased acid-producing capability of the microbiological communities. The rate of nitrate reduction was stable and, accordingly, the required injected nitrate concentration was directly proportional to the duration of the shut-in period.

“Our findings bring important new levels of detail to the forecasting of oilfield reservoir souring and nitrate reduction, by enabling operators to factor in the effect of shut-in periods in their calculations,” adds Matt Streets. “Moreover, they further endorse the formidable capabilities of our pressurised bioreactor suites and DynamicTVS© modelling software in forecasting the likelihood and extent of oilfield reservoir souring.”

About oilfield reservoir souring

Unlike sweet crude oil, which typically contains less than 5% sulfur, sour crude contains a higher percentage of sulfur – an impurity typically recognised through the presence of highly corrosive hydrogen sulfide (H2S) gas. Whether through native geology or geochemistry, sour crude is common across all oil producing regions of the world. However, it is the process of injecting water during secondary recovery operations that can cause a previously sweet oil environment to sour or intensify souring in an already sour reservoir. This is because the injected water will introduce sulfate-reducing microorganisms (SRM) into the reservoir environment. SRM require water, sulfate, an anoxic environment and an energy source (typically the volatile fatty acids [VFAs], the residual crude oil). Add a pH of 4 to 9, a temperature of 10°C to 80°C and a pressure range from 1 psig to 10,000 psig, and the elements are in place for sulfate-reducing microorganisms to flourish, leading to increased concentrations of H2S at the topsides facilities over time. Typically, if unchecked, microbiological reservoir souring goes unnoticed until higher concentrations of hydrogen sulfide are detected in crude oil production. This is because several years of secondary recovery activities may be required before higher levels of H2S are observed. For cost-effective treatment, it is therefore important to forecast an oil reservoir’s ability to sour at the earliest possible opportunity.