Geochemical and sulfate isotopic evolution of flowback and produced waters reveals water-rock interactions following hydraulic fracturing of a tight hydrocarbon reservoir

Osselin, Florian; Saad, Shabab; Nightingale, Michael; Hearn, G.; Desaulty, Anne-Marie; Gaucher, Éric C.; Clarkson, Christopher R.; Kloppmann, Wolfram; Mayer, Bernhard

doi:10.1016/j.scitotenv.2019.07.066

Cited by 40 publications

(27 citation statements)

References 44 publications

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“…Sulfate is a typical secondary anion in produced waters and increases in sulfate concentration can reflect drilling activity, either due to injected chemicals associated with hydraulic fracturing operations ( Paukert Vankeuren et al, 2017 ) or due to injected water reacting with sulfur and sulfate bearing minerals ( Osselin et al, 2019 ). Although anhydrite content is negligible, trace amounts of pyrite have been observed in the Bakken Formation ( Pitman et al, 2001 ; Ashu, 2014 ).…”

Section: Resultsmentioning

confidence: 99%

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Geochemistry and Microbiology Predict Environmental Niches With Conditions Favoring Potential Microbial Activity in the Bakken Shale

et al. 2020

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The Bakken Shale and underlying Three Forks Formation is an important oil and gas reservoir in the United States. The hydrocarbon resources in this region are accessible using unconventional oil and gas extraction methods, including horizontal drilling and hydraulic fracturing. However, the geochemistry and microbiology of this region are not well understood, although they are known to have major implications for productivity and water management. In this study, we analyzed the produced water from 14 unconventional wells in the Bakken Shale using geochemical measurements, quantitative PCR (qPCR), and 16S rRNA gene sequencing with the overall goal of understanding the complex dynamics present in hydraulically fractured wells. Bakken Shale produced waters from this study exhibit high measurements of total dissolved solids (TDS). These conditions inhibit microbial growth, such that all samples had low microbial loads except for one sample (well 11), which had lower TDS concentrations and higher 16S rRNA gene copies. Our produced water samples had elevated chloride concentrations typical of other Bakken waters. However, they also contained a sulfate concentration trend that suggested higher occurrence of sulfate reduction, especially in wells 11 and 18. The unique geochemistry and microbial loads recorded for wells 11 and 18 suggest that the heterogeneous nature of the producing formation can provide environmental niches with conditions conducive for microbial growth. This was supported by strong correlations between the produced water microbial community and the associated geochemical parameters including sodium, chloride, and sulfate concentrations. The produced water microbial community was dominated by 19 bacterial families, all of which have previously been associated with hydrocarbon-reservoirs. These families include Halanaerobiaceae, Pseudomonadaceae, and Desulfohalobiaceae which are often associated with thiosulfate reduction, biofilm production, and sulfate reduction, respectively. Notably, well 11 was dominated by sulfate reducers. Our findings expand the current understanding of microbial life in the Bakken region and provide new insights

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Section: Resultsmentioning

confidence: 99%

“…fracturing operations (Paukert Vankeuren et al, 2017) or due to injected water reacting with sulfur and sulfate bearing minerals (Osselin et al, 2019). Although anhydrite content is negligible, trace amounts of pyrite have been observed in the Bakken Formation (Pitman et al, 2001;Ashu, 2014).…”

Section: Bakken Shale Exhibits High Tds Primarily Comprised Of Nacl Amentioning

confidence: 99%

Geochemistry and Microbiology Predict Environmental Niches With Conditions Favoring Potential Microbial Activity in the Bakken Shale

et al. 2020

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“…However, FBW samples do not plot perfectly on a Rayleigh fractionation trend for sulfate reduction (process a, b, and c in Figure 4) with S isotope enrichment factors ranging from −60‰ to −9‰ (Krouse & Mayer, 2000; Mayer et al, 2007). Because O 2 is present in FRW and atmospheric O 2 is entrained in the injected FRW (Xu et al, 2018; Zolfaghari et al, 2016) and other oxidizers (such as a persulfate breaker or H 2 O 2 ) are added to fracturing fluids at shale gas sites (Osselin et al, 2019; Phan et al, 2020), and because there are always pyrite minerals in shales (Heller & Zoback, 2014), oxidation of pyrites after hydraulic fracturing and during initial flowback is very likely (Osselin et al, 2019; Paukert Vankeuren et al, 2017; Xu et al, 2018; Zolfaghari et al, 2016). Laboratory experiments have revealed evidence for oxidation of pyrites (Pearce et al, 2018; Xu et al, 2018; d and e in Figure 4), which would contribute additional SO 4 to the FBW.…”

Section: Resultsmentioning

confidence: 99%

“…Also, previous research suggested that most WRI may occur at the very early stage of flowback and that mixing becomes increasingly dominant in controlling the chemical and isotopic composition in flowback at the late stage (Kondash et al, 2017). Therefore, daily sampling at the initial stage after hydraulic fracturing (Osselin et al, 2019; Phan et al, 2020) may not be sufficient for characterizing geochemical processes in detail. In addition, when the water chemistry of FBW is mainly controlled by the mixing process between FRW and FOW with very high salinity (tens to hundreds of g/L), the geochemical processes like cation exchanges and adsorption/desorption occurring at the very early stage of flowback may be masked.…”

Section: Introductionmentioning

confidence: 99%

Identification of Geochemical Processes During Hydraulic Fracturing of a Shale Gas Reservoir: A Controlled Field and Laboratory Water‐Rock Interaction Experiment

Huang

Mayer

et al. 2020

Geophysical Research Letters

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A detailed study on geochemical processes following hydraulic fracturing can provide important information on the origin of solutes and potential improvement of fracturing technology. However, this remains difficult due to the low resolution of flowback water and high salinity of formation water. To fill this knowledge gap, a shale-gas well was drilled and freshwater was used to fracture the shale. In parallel, laboratory water-rock interaction experiments were conducted. The intensive sampling for flowback water and the use of multiple isotopes provided novel and detailed insights into the water-rock interactions after hydraulic fracturing. The results showed that beyond mixing processes, cation exchange, adsorption/desorption, and barite precipitation were observed both in the laboratory and field studies. Although oxidation of pyrite was observed in most of the laboratory experiments, our findings demonstrate that this process was not evident in field flowback samples that were dominated by mixing of fracturing fluids and formation water. Plain Language Summary The hydraulic fracturing technologies have paved the way toward the development of unconventional shale gas from low-permeability shale reservoirs. The solutes in flowback water after hydraulic fracturing of shale gas reservoirs can originate from injected fracturing fluids and formation water, but may also be derived from solutes liberated by geochemical reactions. However, in most cases, the laboratory data do not match the field data from hydraulically fractured wells. To date, a further refined understanding of geochemical reactions after hydraulic fracturing occurred is critical for tracing the origin of solutes in flowback water (as the main potential pollutants for near-surface environments) and potentially improving the fracturing technology. Except for reported cation exchange and carbonate dissolution, this study showed several new findings, including nitrate adsorption/desorption and limited oxidation of pyrite in field flowback samples that were dominated by mixing of fracturing fluids and formation water, although oxidation of pyrite was observed in most of the laboratory experiments and expected to be comprehensive during field flowback after hydraulic fracturing. Therefore, the potential creation of matrix porosity induced by water-rock interactions of oxidation of pyrite and further induced dissolution of minerals may be limited.

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“…Based on the analysis of water-rock interaction, Hu et al (2019) explored the impact of oil shale on the groundwater environment during in situ mining, and found that oil shale mining caused the continuous pollution of groundwater. Additionally, in order to understand the interaction between the formation and the fracturing fluid during tight gas exploitation, and the consequences of this interaction, Osselin et al (2019) analyzed water samples from 17 different production wells collected in the same area. They found that the water-rock interaction process increased the oxidation level of the fracturing fluid.…”

Section: Introductionmentioning

confidence: 99%

Experimental Investigation of the Mechanical Failure Behavior of Coal Specimens With Water Intrusion

et al. 2020

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Mining fissures formed by coal mining can easily open bedrock and loose aquifers, and can thus cause water-rock interaction. The strength of coal and rock and their pore and fracture development characteristics are closely related to moisture content. Therefore, this paper studied the strength, porosity, fracture propagation, and failure characteristics of coal with different moisture contents. Six representative coal samples with different moisture contents of 0, 3.79, 6.10, 9.17, 11.01, and 11.68% were prepared by non-destructive water immersion experiment, and the samples were analyzed using. Nuclear Magnetic Resonance (NMR) and uniaxial compression acoustic emission experiments. Then, the temporal and spatial variation of the moisture contents of the coal samples and the characteristics of crack propagation and failure were studied before and after water immersion. Non-destructive water immersion and NMR analysis showed that the moisture content increases exponentially with increasing water immersion time and immersion frequency. Additionally, it was shown that with increasing water immersion time and frequency, the moisture distribution within the coal samples changes from uneven to uniform, and micro-pores and meso-pores develop into larger pores with increasing water content. A coupled uniaxial compression-acoustic emission experiment showed that acoustic emissions are closely related to the macroscopic failure mode of the coal sample. With increasing sample moisture content, the degree of sample destruction and the concentration of acoustic emissions both reduced. The increase of moisture content promotes the change of the macroscopic failure mode of the coal samples from tensile failure to tensile-shear composite failure. The results of this study have important reference value for analyzing the stability of coal pillars and surrounding rock under the action of water, and especially for the design of coal pillar dam bodies in coal mines with groundwater reservoirs.

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Geochemical and sulfate isotopic evolution of flowback and produced waters reveals water-rock interactions following hydraulic fracturing of a tight hydrocarbon reservoir

Cited by 40 publications

References 44 publications

Geochemistry and Microbiology Predict Environmental Niches With Conditions Favoring Potential Microbial Activity in the Bakken Shale

Geochemistry and Microbiology Predict Environmental Niches With Conditions Favoring Potential Microbial Activity in the Bakken Shale

Identification of Geochemical Processes During Hydraulic Fracturing of a Shale Gas Reservoir: A Controlled Field and Laboratory Water‐Rock Interaction Experiment

Experimental Investigation of the Mechanical Failure Behavior of Coal Specimens With Water Intrusion

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