It is accepted that sulphate reducing bacteria (SRB) and certain general heterotrophic bacteria (GHB) can promote pit corrosion of topside and downhole equipment and cause formation damage in the reservoir including H2S souring. In order to inhibit microbial growth and hence minimise these damage mechanisms, it is necessary to impose a strict microbial monitoring regime that can be used to optimise any biocide treatments. There are two major considerations relating to microbial monitoring which must be taken into account which are planktonic microbes (those in suspension) and sessile microbes (those attached as a biofilm). By monitoring the numbers of SRB/GHB entering and leaving each component of the topside process system it is possible to determine whether each is under good microbial control. If numbers are found to increase from inlet to outlet, then biocide treatment at a suitable concentration, can be used to treat the fouled components before pit corrosion or H2S production becomes a serious problem within the component. If the biocide treatment is not performed in time the system downstream may also become contaminated. By carefully monitoring each process system including injection water, firewater, cooling medium, and production systems, it is possible to extend the process equipment lifetime considerably, resulting in a major saving in equipment replacement and lost shut down time. This paper describes the microbial monitoring techniques required to minimise corrosion, biopolymer, insoluble metal sulphide and H2S production both topside and downhole.


The action of SRB in causing microbially influenced corrosion of steal is well documented.1–6 If allowed to go unchecked in oilfield process systems pit corrosion can result with subsequent expensive equipment/pipework replacement being necessary. In addition to SRB corrosion, the growth of GHB can result in polymer precipitation and acid production which can further aid the corrosion process and act as a substrate for sessile biofilm development.7

In seawater injection systems SRB/GHB growth is most evident within the deaerator towers and downstream into the injection downhole tubulars. In production systems the activity of SRB/GHB can occur both downhole in the reservoir, production tubulars and topside in the separators and downstream process equipment towards the export oil pipeline.

Oil and water pipelines can also suffer SRB/GHB related corrosion particularly in the six o'clock position where abrasion of the sulphide layer can occur. This results from particulates (sand, corrosion fragments) dragging along the bottom of the pipeline exposing fresh metal to SRB pit corrosion with a pronounced groove being developed.

In order for SRB to grow, sulphate together with a suitable carbon source, usually volatile fatty acids such as acetate, are necessary. The source of carbon in seawater injection systems is normally from bacterial breakdown of algae and zooplankton (copepods) which is greatest during bloom periods in the local region. In the North Sea the algal and copepod bloom occurs twice a year around the end of spring and again in the autumn, with promoted SRB growth at these times in response to the elevated carbon in the injection topside equipment. The source of sulphate is present in the seawater itself. The source of carbon in production systems is mainly volatile fatty acids from the crude oil such as formate, acetate, propionate and butyrate. The sulphate in the production system originates from either the native formation brine (connate water) or a mixture of seawater (from injection seawater break-through) and formation brine. The higher the carbon and sulphate concentrations then the more likely a system will support SRB growth and be more prone to suffer microbially influenced corrosion.

This content is only available via PDF.
You can access this article if you purchase or spend a download.