Assessment of Oilfield Souring Mechanisms by Mass Spectrometry Analysis of the Sulfur Isotopes Ratio
- Marcio de Oliveira Martins (Petrobras) | Luiz Carlos do Carmo Marques (Petrobras)
- Document ID
- Society of Petroleum Engineers
- International Oil Conference and Exhibition in Mexico, 31 August-2 September, Cancun, Mexico
- Publication Date
- Document Type
- Conference Paper
- 2006. Society of Petroleum Engineers
- 5.4.10 Microbial Methods, 4.3.4 Scale, 5.2 Reservoir Fluid Dynamics, 1.6 Drilling Operations, 4.1.2 Separation and Treating, 4.1.5 Processing Equipment, 2 Well Completion, 5.4.1 Waterflooding, 4.6 Natural Gas, 5.5 Reservoir Simulation, 4.2.3 Materials and Corrosion, 2.7.1 Completion Fluids, 3 Production and Well Operations
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Reservoir souring is defined as the increase mass of gaseous Hydrogen Sulfide (H2S) per unit mass of produced fluids. Unless the onset of H2S takes place either during the appraisal of the well or in the very early stages of oil and/or gas production, it is not quite straightforward to identify the origin of souring. Under reservoir conditions, H2S is extremely reactive thus being able to react with native H2S-sequestering agents and be converted to metallic sulfides, elemental sulfur or organic sulfur compounds. This phenomenon can account for the delay of the onset of souring in the producer wells.
It is a common practice in offshore facilities to prepare the drilling, completion and work-over fluids using seawater which is rich in sulfate and contains sulfate-reducing-bacteria (SRB). Should these fluids be lost to formation there is potential of (anthropogenic) reservoir souring promoted by these bacteria. In most situations, these fluids have always to bear the blame of reservoir souring (and many other problems). But it is not always correct to blame these fluids, because huge amounts of treated seawater are also injected in the formation (water flooding) for secondary recovery. Besides, H2S may be derived from non-anthropogenic sources. Consequently, a given souring problem may be derived from different sources and the existence of multiple possibilities render the souring identification a kind of difficult sometimes. But, this problem can be solved with the aid of instrumental analytical tools.
The sulfur isotopic ratio (34S/32S) determination by Mass Spectrometry (MS) has been used to identify the H2S genesis, a key to properly address this controversial issue. This paper focuses on the use of this analytical tool to determine the sulfur isotope ratio and, therefore, to identify the source of souring. This paper also presents case histories on the use of MS to address souring problems that took place after workover jobs done in Campos Basin. Some aspects of reservoir souring mechanisms and SRB behavior are discussed as well.
Seawater is the only fluid available in large amounts for most production facilities in marine environments. So, this fluid is frequently used as injection water. By the same token, seawater is also used to prepare the different fluids employed in drilling, completion and workover operations. A high sulfate concentration (circa 2800 mg/L), a relatively low salinity (compared to formation water) and the presence of native SRB render the seawater a potential vector for SRB growth in the reservoir. So, when seawater is mixed with formation water it may generate an operational window for SRB growth and reservoir souring.
In spite of microbiological monitoring of injection seawater quality be carried out on a regular basis, in the long term, it is impossible to keep any seawater injection system SRB-free and sterile along the productive life cycle of the wells. A long term plan to deal with this crucial problem still remains elusive. A recent survey shows that souring problems related to seawater injection are experienced by many operators worldwide.(1)
An approach which has been adopted by Petrobras to deal with the problem in new projects is to complete the producers with sour-service (2) equipments/materials, if they will go through the influence of seawater from injectors. As per our current understanding the extra capital expenditure to complete the producers with special alloys - rather than ordinary steel - is completely necessary to rule out any possibility of catastrophic corrosion problems as sulfide stress cracking.(3) Besides safety concerns, another key point to support this approach is the workover cost (deepwater-rig costs are huger than ever in history) to replace ordinary steel materials and tubulars by sour service ones.
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