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Flow-back and produced waters from shale gas and shale oil fields contain high ammonium, which can be formed by methanogenic degradation of methylamines into methane and ammonium. Methylamines are added to fracturing fluid to prevent clay swelling or can originate from metabolism of the osmolyte triglycinebetaine (GB).
We analyzed field samples from a shale gas reservoir in the Duvernay Formation and from a shale oil reservoir in the Bakken formation in Canada to determine the origin of high ammonium. Fresh waters used to make fracturing fluid, early flow-back waters, and late flow back waters from the shale gas reservoir had increasing salinity of 0.01, 0.58, and 2.66 Meq of NaCl, respectively. Microbial community analyses reflected this fresh water to saline transition with halophilic taxa including Halomonas, Halanaerobium, and Methanohalophilus being increasingly present. Early and late flow-back waters had high ammonium concentrations of 32 and 15 mM, respectively.
Such high concentrations had also been found in the Bakken produced waters.
Enrichment cultures of Bakken produced waters in medium containing mono, di-, or trimethylamine, or triglycinebetaine (GB) converted these substrates into ammonium (up to 20 mM) and methane. The methylotrophic methanogen Methanohalophilus, which uses methylamines for its energy metabolism and uses GB as an osmolyte, was a dominant community member in these enrichments. Halanaerobium was also a dominant community member that metabolizes GB into trimethylamine, which is then metabolized further by Methanohalophilus. However, the micromolar concentrations of GB measured in shale reservoirs make them an unlikely source for the 1,000-fold higher ammonium concentrations in flow-back waters. This ammonium either originates directly from the reservoir or is formed from methylamines, which originate from the reservoir, or are added during the hydraulic fracturing process. These methylamines are then converted into ammonium and methane by halophilic methylotrophic methanogens, such as Methanohalophilus, present in flow-back waters.
The survey of Canadian shale sites showed a dominance of halophilic microorganisms, including Halomonas (HA). Nitrate-amended incubations of the field samples under high salinity (14.6% NaCl), revealed a dominance of HA (>72%) and an accumulation of nitrite. Nitrite accumulation directly inhibited the growth of SRB, thereby decreasing their souring and corrosion risks. However, accumulated nitrite may also contribute to iron corrosion, which will be tested by using different concentrations of nitrate as an electron acceptor to HA. Different salinities are further tested on HA strains supplemented with iron coupons to determine their effects on iron corrosion rates. HA incubated with separate cultures of corrosive methanogen and SRB were tested to determine whether a positive or adverse effect will occur between them. Lastly, analyses of iron coupons will be conducted using TOF-SIMS, FIB-SEM and EDS for corrosion product characterization