Thermodesulforhabdus norvegicus gen. nov., sp. nov., a novel thermophilic sulfate-reducing bacterium from oil field water

A novel gram-negative, thermophilic, acetate-oxidizing, sulfate-reducing bacterium, strain A8444, isolated from hot North Sea oil field water, is described. The rod-shaped cells averaged 1 μm in width and 2.5 μm in length. They were motile by means of a single polar flagellum. Growth was observed between 44 and 74°C, with an optimum at 60°C. Spores were not produced. Sulfate and sulfite were used as electron acceptors. Sulfur, thiosulfate, nitrate, fumarate, and pyruvate were not reduced. In the presence of sulfate, growth was observed with acetate, lactate, pyruvate, butyrate, succinate, malate, fumarate, valerate, caproate, heptanoate, octanoate, nonadecanoate, decanoate, tridecanoate, pentadecanoate, palmitate, heptadecanoate, stearate, and ethanol. Pyruvate, lactate, and fumarate did not support fermentative growth. Cytochromes of the c-type were present. Desulfoviridin, desulforubidin, P582, and desulfofuscidin were not present. The G+C content of the DNA was 51 mol%. Sequence analysis of 16S rDNA showed that phylogenetically strain A8444 belongs to the delta subdivision of the Proteobacteria. The closest relatives are Desulfacinum infernum and Syntrophobacter wolinii. Strain A8444 is described as the type strain of the new taxon Thermodesulforhabdus norvegicus gen. nov., sp. nov. Received: 4 May 1995 / Accepted: 11 July 1995     

Archaeoglobus fulgidus Isolated from Hot North Sea Oil Field Waters

A hyperthermophilic sulfate reducer, strain 7324, was isolated from hot (75 degrees C) oil field waters from an oil production platform in the Norwegian sector of the North Sea. It was enriched on a complex medium and isolated on lactate with sulfate. The cells were nonmotile, irregular coccoid to disc shaped, and 0.3 to 1.0 mum wide. The temperature for growth was between 60 and 85 degrees C with an optimum of 76 degrees C. Lactate, pyruvate, and valerate plus H(2) were utilized as carbon and energy sources with sulfate as electron acceptor. Lactate was completely oxidized to CO(2). The cells contained an active carbon monoxide dehydrogenase but no 2-oxoglutarate dehydrogenase activity, indicating that lactate was oxidized to CO(2) via the acetyl coenzyme A/carbon monoxide dehydrogenase pathway. The cells produced small amounts of methane simultaneously with sulfate reduction. F(420) was detected in the cells which showed a blue-green fluorescence at 420 nm. On the basis of morphological, physiological, and serological features, the isolate was classified as an Archaeoglobus sp. Strain 7324 showed 100% DNA-DNA homology with A. fulgidus Z, indicating that it belongs to the species A. fulgidus. Archaeoglobus sp. has been selectively enriched and immunomagnetically captured from oil field waters from three different platforms in the North Sea. Our results show that strain 7324 may grow in oil reservoirs at 70 to 85 degrees C and contribute to hydrogen sulfide formation in this environment.     

Distribution of thermophilic marine sulfate reducers in north sea oil field waters and oil reservoirs

The distribution of thermophilic marine sulfate reducers in produced oil reservoir waters from the Gullfaks oil field in the Norwegian sector of the North Sea was investigated by using enrichment cultures and genus-specific fluorescent antibodies produced against the genera Archaeoglobus, Desulfotomaculum, and Thermodesulforhabdus. The thermophilic marine sulfate reducers in this environment could mainly be classified as species belonging to the genera Archaeoglobus and Thermodesulforhabdus. In addition, some unidentified sulfate reducers were present. Culturable thermophilic Desulfotomaculum strains were not detected. Specific strains of thermophilic sulfate reducers inhabited different parts of the oil reservoir. No correlation between the duration of seawater injection and the numbers of thermophilic sulfate reducers in the produced waters was observed. Neither was there any correlation between the concentration of hydrogen sulfide and the numbers of thermophilic sulfate reducers. The results indicate that thermophilic and hyperthermophilic sulfate reducers are indigenous to North Sea oil field reservoirs and that they belong to a deep subterranean biosphere.     

Biogenic methane production in formation waters from a large gas field in the North Sea

Methanogenesis was investigated in formation waters from a North Sea oil rimmed gas accumulation containing biodegraded oil, which has not been subject to seawater injection. Activity and growth of hydrogenotrophic methanogens was measured but acetoclastic methanogenesis was not detected. Hydrogenotrophic methanogens showed activity between 40 and 80°C with a temperature optimum (ca. 70°C) consistent with in situ reservoir temperatures. They were also active over a broad salinity range, up to and consistent with the high salinity of the waters (90 g l⁻¹). These findings suggest the methanogens are indigenous to the reservoir. The conversion of H₂ and CO₂ to CH₄ in methanogenic enrichments was enhanced by the addition of inorganic nutrients and was correlated with cell growth. Addition of yeast extract also stimulated methanogenesis. Archaeal 16S rRNA gene sequences recovered from enrichment cultures were closely related to Methanothermobacter spp. which have been identified in other high-temperature petroleum reservoirs. It has recently been suggested that methanogenic oil degradation may be a major factor in the development of the world’s heavy oils and represent a significant and ongoing process in conventional deposits. Although an oil-degrading methanogenic consortium was not enriched from these samples the presence and activity of communities of fermentative bacteria and methanogenic archaea was demonstrated. Stimulation of methanogenesis by addition of nutrients suggests that in situ methanogenic biodegradation of oil could be harnessed to enhance recovery of stranded energy assets from such petroleum systems.     

Inhibition of microbial H<Subscript>2</Subscript>S production in an oil reservoir model column by nitrate injection

The effect of nitrate addition on microbial H2S production in a seawater-flooded oil reservoir model column with crude oil as carbon and energy source was investigated. Injection of 0.5 mM nitrate for 2.5-3.5 months led to complete elimination of H2S (initially 0.45-0.67 mM). The major decline in H2S level coincided with the first complete nitrate consumption and production of nitrite. When nitrate was excluded, H2S production resumed after approximately 2.5 months and reached previous levels after approximately 5 months. Using a fluorescent antibody technique, three populations each of sulfate-reducing bacteria (SRB) and nitrate-reducing bacteria (NRB) were monitored. SRB dominated the anoxic zone prior to nitrate addition, comprising 64-93% of the total bacterial population. The monitored NRB constituted less than 6% and no increase was observed during nitrate addition (indicating that other, unidentified, NRB populations were present). After 1-3 months without significant H2S production (3.5-5.5 months with nitrate), the SRB population collapsed, the fraction being reduced to 9-25%. The dominant SRB strain in the column, which constituted on average 94% of the monitored SRB population, was partly/completely inhibited by 50/75 microM nitrite in batch culture tests. Similar nitrite concentrations (50-150 microM) were detected in the column when the H2S level declined, indicating that nitrite inhibition was the main cause of H2S elimination. The results from this study indicate that nitrate/nitrite can be used to prevent detrimental SRB activity in oil reservoirs.     

Penetration of Sulfate Reducers through a Porous North Sea Oil Reservoir

The presence of mesophilic benzoate-degrading sulfate-reducing bacteria in the water systems of three Norwegian oil platforms was investigated. Strain 4502 was isolated from the injection water system, and specific antibodies were produced against this isolate. It was present in the injection water system during a period of 3 years, but not in the in situ reservoir water. Later it was found in water samples collected from the oil field production system. This showed that strain 4502 had penetrated the reservoir together with the injection water and eventually reached the production well.