Simulating the Sour Subsurface… and Beyond Matt Streets
S ince the earliest days of hydrocarbon extraction (circa 1920), sulfate-reducing prokaryotes (SRP) have been observed in production fluid samples. These microbes reduce sulfate to hydrogen sulfide (H 2 S) – an extremely corrosive and toxic compound known to ‘eat away’ at the metallurgy in production facilities. The production of sour (i.e. sulfide-containing) fluid is considered to carry huge economic costs within the Energy sector. For example, in the United States upstream Oil and Gas (O&G) industry alone, it is estimated that corrosion costs around $1.4B each year, with a significant proportion of this being attributed to material exposure to H 2 S. However, only in the past 30 years has the activity of SRP in water-flooded assets been recognised as the main cause of oilfield reservoir souring. Even today, laboratory research and computer modelling continue to investigate these complex microbial interactions in the sour subsurface to better understand and predict the appearance of this phenomenon. Rooted in biology In the late 1980s, a joint industry project (JIP) was launched in the UK to evaluate and determine why some historically ‘sweet’ (i.e., non-sulfide-containing) North Sea oilfield reservoirs had begun to produce sour fluids. The programme of work, consisting of ten industrial sponsors, was led by a corrosion engineer, Dr Bob Eden (founder of Rawwater). Based on the findings of what was a two-and-a-half-year project, it was concluded that souring commencing from a sweet starting point was linked to water injection and subsurface biological sulfide generation. The JIP was the first research programme in the world to categorically identify the critical role which microbiology plays in oilfield reservoir souring. Further, the outputs of this work included a Nature paper, an HSE-sponsored HMSO report, and the origins for the world’s first oilfield reservoir souring forecasting tool, the DynamicTVS© model.
Surviving the subsurface During the initial production of hydrocarbon from an oilfield, the reservoir pressure is sufficiently high to drive fluids from the reservoir to the wellbore of a production well, for production at the topsides facility. This is termed ‘primary recovery’. As the pressure of the reservoir decreases over time, additional downhole pressure is required to maintain successful oil production. This is typically achieved through the injection of water into the formation and is termed ‘secondary recovery’. However, this process of ‘water-flooding’ will introduce SRP and other bacteria into the subsurface environment, typically contaminating the near wellbore of the injection well. Depending on the source of the injection water, significant sulfate concentrations are also introduced. For example, seawater typically contains around 2,700 mg sulfate l –1 (28 mM). Despite the relatively high pressures and temperatures which initially exist in oilfield reservoirs when compared with physical conditions at sea level, the act of injecting large volumes of cold, sulfate-containing water into the formation significantly reduces the temperature of the environment close to the base of the injector. During the initial production of hydrocarbon from an oilfield, the reservoir pressure is sufficiently high to drive fluids from the reservoir to the wellbore of a production well, for production at the topsides facility.
16 Microbiology Today May 2023 | microbiologysociety.org
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