Bacteria containing magnetosomes (protein-bound nanoparticles of magnetite or greigite) are common to many sedimentary habitats, but have never been found before to live within another organism. Here, we show that octahedral inclusions in the extracellular symbionts of the marine bivalve Thyasira cf. gouldi contain iron, can exhibit magnetic contrast and are most likely magnetosomes. Based on 16S rRNA sequence analysis, T. cf. gouldi symbionts group with symbiotic and free-living sulfur-oxidizing, chemolithoautotrophic gammaproteobacteria, including the symbionts of other thyasirids. T. cf. gouldi symbionts occur both among the microvilli of gill epithelial cells and in sediments surrounding the bivalves, and are therefore facultative. We propose that free-living T. cf. gouldi symbionts use magnetotaxis as a means of locating the oxic-anoxic interface, an optimal microhabitat for chemolithoautotrophy. T. cf. gouldi could acquire their symbionts from near-burrow sediments (where oxic-anoxic interfaces likely develop due to the host's bioirrigating behavior) using their superextensile feet, which could transfer symbionts to gill surfaces upon retraction into the mantle cavity. Once associated with their host, however, symbionts need not maintain structures for magnetotaxis as the host makes oxygen and reduced sulfur available via bioirrigation and sulfur-mining behaviors. Indeed, we show that within the host, symbionts lose the integrity of their magnetosome chain (and possibly their flagellum). Symbionts are eventually endocytosed and digested in host epithelial cells, and magnetosomes accumulate in host cytoplasm. Both host and symbiont behaviors appear important to symbiosis establishment in thyasirids.

Microbes in unconventional gas operations can conceivably contribute to (i) degradation of polymers in hydraulic fracturing fluid, (ii) well plugging, limiting gas flow and (iii) souring and corrosion due to activity of sulfate reducing bacteria (SRB). Flowback waters from a tight gas field in Northern British Columbia were distinct from the fresh water, used for making hydraulic fracturing fluid, by their high salinity, low pH and high ammonium concentrations. Microbial counts of SRB and of acid-producing bacteria (APB) for these flowback waters were significantly lower than for the fresh water used to make the hydraulic fracturing fluid. Determining microbial community compositions by sequencing the 16S rRNA genes in the samples did not indicate the presence of microbes preferring high salt or high temperature conditions in samples of flowback water. These data indicate that these tight gas formations are sterile and that the microbes that are being introduced with the hydraulic fracturing fluid do not thrive downhole. Hence, microbes downhole are unlikely to contribute to well plugging, limiting gas flow. Microbes at or near the surface may cause polymer degradation in hydraulic fracturing fluid, especially when guar gum is used in gel-based fracturing treatments, and may cause souring in the fresh water, used for making hydraulic fracturing fluid, if this contains a significant concentration of sulfate.

Microorganisms contribute to souring and corrosion in oil and gas field systems. Biocides and/or nitrate can be used to mitigate the negative effects associated with these microbial activities. In order to determine the success of or the need for these measures we use a number of analytical tools on aqueous or solid field samples: (i) spectrophotometric and HPLC assays are used to monitor key analytes (sulfate, sulfide, nitrate, nitrite and others), (ii) microbial assays are used to determine numbers and activities of key microbes and (iii) sequencing of PCR amplicons, typically of a portion of the 16S rRNA genes is used to determine microbial community compositions in field samples. The trick is to combine the information to arrive at a comprehensive view of what is happening and what action may be needed. For instance, a shale gas and a shale oil field in North West Canada, appear to have similar water chemistry. Both are highly saline but halophilic (salt loving) SRB were only found in samples from the shale oil not in those from the shale gas field, which appears related to the different temperatures in these fields of 30-35°C and 75-100°C, respectively. Hence, mitigation measures aimed at killing bacteria downhole may be appropriate for these shale oil but not for these shale gas environments.