Oilfield Souring

Reservoir Forecasting

What is Microbiological Oilfield Souring?

Whether as a result of native geology or geochemistry, sour crude is common across all oil producing regions of the world. Unlike sweet crude, which typically contains below 5% sulfur, sour crude has a higher percentage of sulfur – an impurity which can make its presence known through acrid, highly corrosive hydrogen sulfide (H2S) gas.

Compared to sweet oil, sour crude is more expensive to refine, presents a significant corrosion risk to assets and incurs higher chemical treatment costs. So, what makes a previously sweet oil environment turn sour… and why can higher levels of hydrogen sulfide be observed in a reservoir that already has a degree of souring? The answer lies in a phenomenon known as microbiological oilfield souring.

Introducing sulfate-reducing microorganisms

Additional downhole pressure is necessary to successfully extract oil throughout the lifespan of a reservoir – and this is typically achieved by injecting water (often sulfate-rich seawater) during secondary recovery operations. The injected water will introduce sulfate-reducing microorganisms (SRM, often also referred to as sulfate-reducing bacteria or SRB) into the reservoir environment and can even propagate microbial lifeforms that are already present downhole.

The conditions necessary for microbial life

To flourish, SRM require water, sulfate (which is chemically reduced and converted to sulfide), an anoxic (oxygen-free) environment and an energy source (typically the volatile fatty acids (VFAs) and 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.

To assist operators in understanding whether or not their oilfields will sour – and to ensure any risk of souring is identified early enough to allow for economical treatment – data from our pressurised bioreactor studies is used to calibrate DynamicTVS© (Thermal Viability Shell), our predictive oilfield souring tool.

Taking operational, planning and survey data from all stages of oil production, under any temperature and pressure conditions, DynamicTVS© is used to generate future profiles of hydrogen sulfide in all fluid phases. Put simply, the software can forecast if reservoir conditions will support microbiological souring and resultant H2S production – and to what extent.

Oil bottles on test

The DynamicTVS© model describes the cooling of an oil reservoir due to water-flooding, the opportunity for growth of sulfate-reducing microorganisms (SRM) in the cooled zone, the transport of the hydrogen sulfide produced by the SRM to the producer, and the downhole and topsides partitioning of the sulfide at specified pressures and temperatures.

H2S partitioning