Hydraulic fracturing requires the injection of large volumes of fluid to extract oil and gas from low permeability unconventional resources ( e.g. , shale, coalbed methane), resulting in the production of large volumes of highly complex and variable waste fluids. Shale gas fluid samples were collected from two hydraulically fractured wells in Morgantown, WV, USA at the Marcellus Shale Energy and Environment Laboratory (MSEEL) and analyzed using ultrahigh resolution mass spectrometry to investigate the dissolved organic sulfur (DOS) pool. Using a non-targeted approach, ions assigned DOS formulas were analyzed to identify dominant DOS classes, describe their temporal trends and their implications, and describe the molecular characteristics of the larger DOS pool. The average molecular weight of organic sulfur compounds in flowback decreased and was lowest in produced waters. The dominant DOS classes were putatively assigned to alcohol sulfate and alcohol ethoxysulfate surfactants, likely injected as fracturing fluid additives, on the basis of exact mass and homolog distribution matching. This DOS signature was identifiable 10 months after the initial injection of hydraulic fracturing fluid, and an absence of genes that code for alcohol ethoxysulfate degrading proteins ( e.g. , sulfatases) in the shale well genomes and metagenomes support that these additives are not readily degraded biologically and may continue to act as a chemical signature of the injected fluid. Understanding the diversity, lability, and fate of organic sulfur compounds in shale wells is important for engineering productive wells and preventing gas souring as well as understanding the consequences of unintended fluid release to the environment. The diversity of DOS, particularly more polar compounds, needs further investigation to determine if the identified characteristics and temporal patterns are unique to the analyzed wells or represent broader patterns found in other formations and under other operating conditions.
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Toxicity of hydraulic fracturing wastewater from black shale natural-gas wells influenced by well maturity and chemical additives
Hydraulic fracturing of deep shale formations generates large volumes of wastewater that must be managed through treatment, reuse, or disposal. Produced wastewater liberates formation-derived radionuclides and contains previously uncharacterized organohalides thought to be generated within the shale well, both posing unknown toxicity to human and ecological health. Here, we assess the toxicity of 42 input media and produced fluid samples collected from four wells in the Utica formation and Marcellus Shale using two distinct endpoint screening assays. Broad spectrum acute toxicity was assessed using a bioluminescence inhibition assay employing the halotolerant bacterium Aliivibrio fischeri , while predictive mammalian cytotoxicity was evaluated using a N -acetylcysteine (NAC) thiol reactivity assay. The acute toxicity and thiol reactivity of early-stage flowback was higher than later produced fluids, with levels diminishing through time as the natural gas wells matured. Acute toxicity of early stage flowback and drilling muds were on par with the positive control, 3,5-dichlorophenol (6.8 mg L −1 ). Differences in both acute toxicity and thiol reactivity between paired natural gas well samples were associated with specific chemical additives. Samples from wells containing a larger diversity and concentration of organic additives resulted in higher acute toxicity, while samples from a well applying a higher composition of ammonium persulfate, a strong oxidizer, showed greater thiol reactivity, predictive of higher mammalian toxicity. Both acute toxicity and thiol reactivity are consistently detected in produced waters, in some cases present up to nine months after hydraulic fracturing. These results support that specific chemical additives, the reactions generated by the additives, or the constituents liberated from the formation by the additives contribute to the toxicity of hydraulic fracturing produced waters and reinforces the need for careful consideration of early produced fluid management.
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- Award ID(s):
- 1632892
- NSF-PAR ID:
- 10311143
- Date Published:
- Journal Name:
- Environmental Science: Processes & Impacts
- Volume:
- 23
- Issue:
- 4
- ISSN:
- 2050-7887
- Format(s):
- Medium: X
- Sponsoring Org:
- National Science Foundation
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Abstract Recent advances in shale gas development have largely outpaced efforts to manage associated waste streams that pose significant environmental risks. Wastewater management presents significant challenges in the Marcellus shale, where increasing fluid volumes concomitant with expanding development will threaten to overwhelm existing infrastructure over the next decade. In this work, we forecast growth in drilling, flowback, and produced fluid volumes through 2025 based on historic data and consider conventional and alternative disposal options to meet future demands. The results indicate that nearly 12 million m3(74 MMbbl) of wastewater will be generated annually by 2025. Even assuming wastewater recycling rates in the region rebound, meeting increased demands for wastewater that cannot be reused due to poor quality or logistics would require significant capital investment to expand existing disposal pathways, namely treatment and discharge at centralized facilities or dedicated brine injection in Ohio. Here, we demonstrate the logistical and environmental advantages of an alternative strategy: repurposing depleted oil and gas wells for dedicated injection of wastewater that cannot otherwise be reused or recycled. Hubs of depleted wells could accommodate projected increases in wastewater volumes more efficiently than existing disposal options, primarily because the proximity of depleted wells to active production sites would substantially reduce wastewater transport distances and associated costs. This study highlights the need to reevaluate regional-scale shale wastewater management practices in the context of evolving wastewater qualities and quantities, as strategic planning will result in more socially and economically favorable options while avoiding adverse environmental impacts that have overshadowed the environmental benefits of natural gas expansion in the energy sector.
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Abstract Background Microbial colonization of subsurface shales following hydraulic fracturing offers the opportunity to study coupled biotic and abiotic factors that impact microbial persistence in engineered deep subsurface ecosystems. Shale formations underly much of the continental USA and display geographically distinct gradients in temperature and salinity. Complementing studies performed in eastern USA shales that contain brine-like fluids, here we coupled metagenomic and metabolomic approaches to develop the first genome-level insights into ecosystem colonization and microbial community interactions in a lower-salinity, but high-temperature western USA shale formation. Results We collected materials used during the hydraulic fracturing process (i.e., chemicals, drill muds) paired with temporal sampling of water produced from three different hydraulically fractured wells in the STACK ( S ooner T rend A nadarko Basin, C anadian and K ingfisher) shale play in OK, USA. Relative to other shale formations, our metagenomic and metabolomic analyses revealed an expanded taxonomic and metabolic diversity of microorganisms that colonize and persist in fractured shales. Importantly, temporal sampling across all three hydraulic fracturing wells traced the degradation of complex polymers from the hydraulic fracturing process to the production and consumption of organic acids that support sulfate- and thiosulfate-reducing bacteria. Furthermore, we identified 5587 viral genomes and linked many of these to the dominant, colonizing microorganisms, demonstrating the key role that viral predation plays in community dynamics within this closed, engineered system. Lastly, top-side audit sampling of different source materials enabled genome-resolved source tracking, revealing the likely sources of many key colonizing and persisting taxa in these ecosystems. Conclusions These findings highlight the importance of resource utilization and resistance to viral predation as key traits that enable specific microbial taxa to persist across fractured shale ecosystems. We also demonstrate the importance of materials used in the hydraulic fracturing process as both a source of persisting shale microorganisms and organic substrates that likely aid in sustaining the microbial community. Moreover, we showed that different physicochemical conditions (i.e., salinity, temperature) can influence the composition and functional potential of persisting microbial communities in shale ecosystems. Together, these results expand our knowledge of microbial life in deep subsurface shales and have important ramifications for management and treatment of microbial biomass in hydraulically fractured wells.more » « less
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Abstract In the last decade, extensive application of hydraulic fracturing technologies to unconventional low-permeability hydrocarbon-rich formations has significantly increased natural-gas production in the United States and abroad. The injection of surface-sourced fluids to generate fractures in the deep subsurface introduces microbial cells and substrates to low-permeability rock. A subset of injected organic additives has been investigated for their ability to support biological growth in shale microbial community members; however, to date, little is known on how complex xenobiotic organic compounds undergo biotransformations in this deep rock ecosystem. Here, high-resolution chemical, metagenomic, and proteomic analyses reveal that widely-used surfactants are degraded by the shale-associated taxa Halanaerobium, both in situ and under laboratory conditions. These halotolerant bacteria exhibit surfactant substrate specificities, preferring polymeric propoxylated glycols (PPGs) and longer alkyl polyethoxylates (AEOs) over polyethylene glycols (PEGs) and shorter AEOs. Enzymatic transformation occurs through repeated terminal-end polyglycol chain shortening during co-metabolic growth through the methylglyoxal bypass. This work provides the first evidence that shale microorganisms can transform xenobiotic surfactants in fracture fluid formulations, potentially affecting the efficiency of hydrocarbon recovery, and demonstrating an important association between injected substrates and microbial growth in an engineered subsurface ecosystem.
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Polyethylene glycols (PEGs) and polypropylene glycols (PPGs) are frequently used in hydraulic fracturing fluids and have been detected in water returning to the surface from hydraulically fractured oil and gas wells in multiple basins. We identified degradation pathways and kinetics for PEGs and PPGs under conditions simulating a spill of produced water to shallow groundwater. Sediment-groundwater microcosm experiments were conducted using four produced water samples from two Denver-Julesburg Basin wells at early and late production. High-resolution mass spectrometry was used to identify the formation of mono- and di-carboxylated PEGs and mono-carboxylated PPGs, which are products of PEG and PPG biodegradation, respectively. Under oxic conditions, first-order half-lives were more rapid for PEGs (<0.4–1.1 d) compared to PPGs (2.5–14 d). PEG and PPG degradation corresponded to increased relative abundance of primary alcohol dehydrogenase genes predicted from metagenome analysis of the 16S rRNA gene. Further degradation was not observed under anoxic conditions. Our results provide insight into the differences between the degradation rates and pathways of PEGs and PPGs, which may be utilized to better characterize shallow groundwater contamination following a release of produced water.more » « less
- Free Publicly Accessible Full Text
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Accepted Manuscript1.0
- Journal Article:
- https://doi.org/10.1039/d1em00023c
