A strictly anaerobic thiosulfate-reducing bacterium was isolated from a corroding offshore oil well in Congo and was designated strain SEBR 4207T. Pure culture of the strain induced a very active pitting corrosion of mild steel, with penetration rates of up to 4 mm per year. This constitutes the first experimental evidence of the involvement of thiosulfate reduction in microbial corrosion of steel. Strain SEBR 4207T cells were vibrios (3 to 5 by 1 pm), stained gram negative, and possessed lateral flagella. Spores were not detected. Optimum growth occurred in the presence of 3% NaCl at pH 7.0 and 42°C. Strain SEBR 4207T utilized peptides and amino acids, but not sugars or fatty acids. It fermented serine, histidine, and Casamino Acids, whereas arginine, glutamate, leucine, isoleucine, alanine, valine, methionine, and asparagine were only used in the presence of thiosulfate. Peptides were fermented to acetate, isobutyrate, isovalerate, 2-methylbutyrate, H,, and CO,. The addition of either thiosulfate or sulfur but not sulfate increased peptide utilization, growth rate, and biomass; during growth, H,S was produced and a concomitant decrease in H, was observed. The addition of either thiosulfate or sulfur also reversed H, inhibition. 16s rRNA sequence analysis indicates that strain SEBR 4207T is distantly related to members of the genus Thermoanuerobacter (83% similarity). Because the phenotypic and phylogenetic characteristics cannot be assigned to any described genus, strain SEBR 4207T is designated as a new species of a new genus, Dethiosulfovibrio peptidovorans gen. nov., sp. nov. Strain SEBR 4207T has been deposited in the Deutsche Sammlung von Mikroorganismen und zellkulturen GmbH (= DSM 11002).In 1989, Elf Congo experienced corrosion of the first 5 km of a 23-km main subsea pipeline that transported sour oil (i.e., H,S-containing petroleum) produced from the Emeraude oil field. The corroded segment was replaced, but it corroded again a year later. The whole line was then replaced and operated under a specifically designed biocide treatment regimen. The preliminary examination of the corroded iron showed that the breakthrough was due to bacterial pitting corrosion, with an unusually high penetration rate of about 1 cm per year. Chemical analysis of the pipeline water revealed the presence of up to 0.5 mM thiosulfate. It is likely that the thiosulfate was produced as a result of oxidation of the H,S naturally present in the oil field ecosystem by oxygen that is introduced in the pipelines during processing (10, 15, 22). The corrosion of pipelines was suspected to be due not only to sulfate but also to thiosulfate reduction by sulfate-reducing bacteria (SRB), because computer modeling had shown that thiosulfate reduction could induce the pitting corrosion of steel at higher rates than sulfate reduction (13).Since the pipeline was under a biocide treatment regimen during our microbiological investigations, the production fluids from several wellheads upstream of the line were collected and analyzed. Besides diffe...
In order to determine the acidity of corrosive media prevailing in oil and gas wells where 00 2 corrosion is encountered, a pH meter has been built which enables pH measurements under pressures from 0.1 up to 100 MPa. The usual physical chemistry of calcocarbonic equilibria is also presented in a new form which better emphasizes the influence of the partial pressure of CO2 as the controlling variable in the system. According to both theoretical and experimental results, the pH of a production water depends as much upon its alkalinity as upon the level of the 002 partial pressure. The effect of calcareous saturation or supersaturation is also emphasized. It is then shown through a survey of production waters that their acidity under well conditions is much weaker than is commonly assumed. This stands for both 00 2 corrosion and sulfide stress cracking.( '>Trade marks.
Several members of the order Thermotogales in the domain Bacteria, viz., Thermotoga neapolitana, Thermotoga maritima, Thermosipho africanus, Fervidobacterium islandicum, and Thermotoga strain SEBR 2665, an isolate from an oil well, reduced thiosulfate to sulfide. This reductive process enhanced cellular yields and growth rates of all the members but was more significant with the two hyperthermophiles T. neapolitana and T. maritima. This is the first report of such an occurrence in this group of thermophilic and hyperthermophilic anaerobic bacteria. The results suggest that thiosulfate reduction is important in the geochemical cycling of sulfur in anaerobic thermal environments such as the slightly acidic and neutral-pH volcanic hot springs and oil reservoirs.
This article discusses the various effects of CO2 on corrosion in general, ELF AQUITAINE's policy for fighting corrosion in offshore wells, the mechanisms of local CO2 attack, and finally, the method of predicting the risks of CO2 corrosion in wells. INTRODUCTION An anti-corrosion policy is just one element of the general approach to oil and gas production, and is therefore sensitive to the overall industrial environment. From this standpoint, the offshore and onshore contexts are often profoundly different. While this is perhaps not true for sour fie1ds, because of the safety requirements around the wells, in the case of sweet fields the difference can be fundamental. CO2 corrosion is in fact an old problem in the oil and gas industry, having been encountered in the United States as early as in the 1940's [1]. Since then, it has been the subject of numerous studies throughout the world [2,3], with peak activities in the 1940's, then in 1980. In spite of this, the problem is still not considered to be completely solved. With hindsight, it can now be seen that there are actually several effects of CO2 on corrosion, and also several problems, depending particularly on the mode of production and its industrial context, and in general, on the production policy of each company. It so happens that the context in which ELF AQUITAINE operates is quite different from the average for the profession, particularly in North America, and that the company's field observations and constraints are also different. The segmented nature of the problem and the specificity of the segments became evident at an early stage. An initial study was published in 1985 [4], and continued progress since then has now led to a new level of understanding. The aim of the present article is therefore to review current knowledge of CO2 corrosion, starting with a description of the variety of the effects of CO2 on corrosion in general, and the resulting diversity of the definitions of corrosivity. The methods employed for predicting the risks of CO2 corrosion are then discussed, based on the specific problems encountered by ELF AQUITAINE, and with the corresponding definition of well corrosivity. THE VARIETY OF THE EFFECTS OF CO2 ON CORROSION AND ON THE RESULTING PROBLEMS Importance and extension of the notion of CO2 partial pressure For millions of years, the CO2 in hydrocarbon deposits has been in equilibrium with the three water, oil and gas phases. The quantity of CO2 present in each phase is therefore proportional to their relative abundance. The variations in concentration result simply from the differences in the solubilities and the activity coefficients in the three phases. Thus, in three phase effluents, which are generally highly turbulent, even though the CO2 equilibrium is never perfect, any deviations remain relatively insignificant. Furthermore, sampling and analysis of CO2 in the high pressure condensed phases is difficult and cannot be transposed from one phase to the other (nor even from one oil to another). For all these reasons, whatever the phase considered and the number of phases present, it is more reasonab1e, and above all much easier, to express the amount of CO2, not in terms of its concentration in each phase, but as its chemical potential.
To solve the problem of CO 2 corrosion, use of 13% Cr production tubings seems to have rapidly increased, and a quick summary of our own experience is given. The difficulty lies essentially in accurately forecasting when stainless steel will be necessary and when the CO 2 corrosion of standard tubings will remain acceptable.For H 2 S corrosion, the differences between the traditional sulfide stress cracking (SSC) problems and the new stress corrosion cracking (SCC) ones are emphasized.
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