Sulphate-reducing bacteria (SRB) can become active in oil fields upon waterflooding to cause reservoir souring by H2S (which is toxic and explosive), and subsequent corrosion of steel in well tubulars, pipelines and process facilities. Accurate predictions of reservoir souring due to SRB are essential for multi-million dollar decisions on oil field development and materials selection. Extremes of pressure (up to 15,000 psi), salinity (up to 200,000 mg/l total dissolved solids) and temperature (greater that 85° C) may be found in deepwater fields and such extremes have been shown to inhibit normal growth of SRB and sulphide generation. Novel high-pressure rated test equipment has been developed and used successfully to investigate reservoir souring under extreme conditions in the laboratory. Such data can be used to model reservoir souring for injection systems using seawater or produced water, and predict H2S generation profiles for individual wells and ultimately entire fields. This allows operators to make informed decisions that can save millions of dollars in capital expenditure and operating costs, particularly for deepwaterprojects.


SRB are responsible for the majority of the bacterial problems in oil production [1]. Hydrogen sulphide is produced directly by SRB as a by-product of respiration. This hazardous gas, a respiratory inhibitor, is volatile and toxic. It also ‘sours’ crude oil and gas, making it harder to refine into environmentally friendly, high quality fuels, hence reducing its value. In addition, sulphide concentrations even below 1 mg/l in the water phase may lead to high corrosion rates, and in the gasphase, maximum allowable limits on H2S are often as low as 3 ppm (v/v) for high pressure duties, to avoid sulphide stress cracking (SSC) in susceptible steels.

Secondary oil production for pressure maintenance often involves seawater injection. Introduced with seawater are high concentrations of sulphate and immigrant microorganisms, despite employment of biocides and filtration. The seawater also cools the reservoir where it enters it, resulting in a near well bore environment very different to that before human intervention. This environment can be ideal for the proliferation of SRB and results in sulphide biogenesis as bacteria reduce sulphate from the seawater in order to respire.

Factors such as carbon and sulphate availability impact SRB growth but extreme environmental conditions can also significantly reduce the activity of SRB ‘2’. Salinity, temperature and pressure, in particular, may be more extreme for deepwater projects. Hence, it is crucial to understand how such conditions may affect souring for a given field. Environmental conditions do vary widely between fields but general information can be used to perform an initial assessment of the souring risk, before more detailed study.

Accurate predictions of reservoir souring due to SRB are essential for multi-million dollar decisions on oil field development and materials selection. For deepwater projects in particular the correct materials selection is critical for the success of the project. Furthermore, once the problem has been characterised properly it is possible to select options to mitigate the problem of sulphide generation by SRB.

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