Assessing the Magnitude and Consequences of Reservoir Souring a report by Mick Schofield,1 James FD Stott2 and Iain Spark3 1. Senior Consultant; 2. Specialist Consultant, Intertek CAPCIS; 3. Executive Consultant, Intertek Commercial Microbiology
Reservoir souring is the unplanned production of increased concentrations
of hydrogen sulphide (H2S) in well-stream fluids from production wells that are subject to water injection for secondary recovery. Souring is typically associated with the breakthrough of injection waters at production wells. The phenomenon is generally acknowledged to be due to the activity of a specialised group of microorganisms, the sulphate-reducing bacteria (SRB).1
The progress of well souring is typically
based on measurement of H2S concentrations in the gas phase at separator conditions. This is important because biogenic H2S originates in the water phase and partitions between water, liquid hydrocarbon and
gas in a manner that is dependent on temperature, pressure, the pH of the aqueous phase, fluid phase ratios and a number of other factors.
Figure 1 shows an electron micrograph of SRB cells of a commonly encountered type (belonging to the genus Desulfovibrio). Low populations of SRB cells are ubiquitous in seawater and many other natural waters that are used for secondary recovery. SRB only become a concern when conditions are suitable for their population density to increase by many orders of magnitude, leading to the generation of concentrations of H2S.
H2S is a poisonous, dense gas with serious safety implications. Furthermore, H2S produced from reservoir souring can lead to sudden catastrophic failure of non-resistant metallic materials from sulphide
stress corrosion cracking (SCC) or hydrogen-induced cracking (HIC),2 and can give rise to enhanced pitting corrosion rates. Iron sulphide
corrosion products from the reaction between H2S and steels also adversely affect field operations, for example by depositing on gas compressor impellers, causing loss of performance, and plugging filters. Fuel gas used for gas turbines quite typically has a requirement
to contain less than 20 parts per million by volume (ppmv) H2S, so reservoir souring can require expensive treatment of produced gas for use on-site or export.
This article describes how the progress of reservoir souring and its consequences for materials can be anticipated, together with currently available options for souring control and their shortcomings.
Hydrogen Sulphide Generation and Mobility SRB are active under oxygen-free conditions; they obtain their required carbon from organic nutrients and their energy from the reduction of sulphate ions to sulphide. This process is termed ‘anaerobic respiration’ and can be summarised as follows:
Sulphate (SO42-) + Organic Carbon →H2S + Water + Carbon Dioxide
The bacteria will only flourish and produce sulphide if they obtain sufficient sulphate and organic carbon. Sulphate is abundant in injected seawater and most shallow aquifer waters, but not usually
© TOUCH BRIEFINGS 2011
In fact, SRB grow in association with other microorganisms in the form of biological slimes known as biofilms, where they adhere to surfaces, rather than as free-floating (‘planktonic’) cells in a moving flood front. This concept is illustrated schematically in
Figure 2, with the supposed zones of H2S generation by SRB marked in green.
In more recent years, doubt began to be cast on the correctness of the deep reservoir mixing zone concept of reservoir souring, for a number of reasons. Firstly, many reservoirs that experience souring seem too hot to sustain SRB activity and it is known that the water mixing zone runs ahead of the zone of substantive cooling. Most SRB that are recovered from oilfield water systems will typically only grow in the temperature range 5–50°C. Some less common groups of SRB have the ability to grow at elevated temperatures. However, these high-temperature SRB are not routinely recovered from sour produced waters in sufficient numbers to convince us of their central role in the souring process.
James FD Stott is a specialist consultant at Intertek CAPCIS in Manchester, one of the largest organisations in Western Europe in the field of corrosion failure investigation, corrosion testing and materials consultancy. He has worked in the field of corrosion and industrial microbial control since 1979, specialising in problems relating to microbial-influenced corrosion, fouling and deposition, particularly in oilfield water systems, water injection systems, production systems and plant under hydrotest.
Iain Spark is an executive consultant at Intertek Commercial Microbiology Ltd in Aberdeen, which is a leading consultancy in microbial corrosion and reservoir souring. He has over 30 years oil industry experience and is an industry expert in formation damage and specialises in all aspects of microbial corrosion and reservoir souring. He has managed a £1.5m research project jointly funded by the Offshore Supplies Office (OSO), the Natural Environment Research Council (NERC) and the Department of Trade and Industry (DTI).
Mick Schofield is a senior consultant with Intertek CAPCIS in Manchester. He specialises in material selection for sour service oilfield processing equipment, particularly the use of corrosion resistant alloys. He also leads corrosion failure investigations worldwide. In his 31-year career in corrosion he has also run a sour service corrosion testing laboratory. He holds a BSc in chemistry and an MSc and PhD in corrosion science from the University of Manchester Institute of Science and Technology.
in formation water; conversely, organic carbon sources, including simple dissolved organic carbon compounds in the form of volatile fatty acids (VFA), are abundant in formation water but not in seawater. For this reason, it was long believed that most SRB activity occurs relatively deep within the reservoir, around interfaces of formation water with injection water, the so-called ‘moving flood front’.3
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