Repository for Oil and Gas Energy Research (ROGER)

Abstract:
Shale gas exploitation by hydraulic fracturing involves a number of environmental hazards, among which the neutralization and management of fracturing flowback waters is of particular importance. Chemical compounds present in the flowback water mainly constitute a threat to surface waters. The aim of our research was to determine the effects of these compounds on the state of activated sludge in a wastewater treatment plant employing biological treatment processes. Based on the obtained results, it was concluded that prior to the transfer of flowback water to a biological wastewater treatment system, it should be diluted with fresh water to lower the chloride ion concentration to the level of 1,000 mg Cl-/dm3. Although such a procedure would ensure the proper performance of a biological wastewater treatment system, it would not limit the migration of phthalates and thihalomethanes to surface waters.

Abstract:
Unconventional oil and gas (UOG) production produces large quantities of wastewater with complex geochemistry and largely uncharacterized impacts on surface waters. In this study, we assessed shifts in microbial community structure and function in sediments and waters upstream and downstream from a UOG wastewater disposal facility. To do this, quantitative PCR for 16S rRNA and antibiotic resistance genes along with metagenomic sequencing were performed. Elevated conductivity and markers of UOG wastewater characterized sites sampled downstream from the disposal facility compared to background sites. Shifts in overall high level functions and microbial community structure were observed between background sites and downstream sediments. Increases in Deltaproteobacteria and Methanomicrobia and decreases in Thaumarchaeota were observed at downstream sites. Genes related to dormancy and sporulation and methanogenic respiration were 18–86 times higher at downstream, impacted sites. The potential for these sediments to serve as reservoirs of antimicrobial resistance was investigated given frequent reports of the use of biocides to control the growth of nuisance bacteria in UOG operations. A shift in resistance profiles downstream of the UOG facility was observed including increases in acrB and mexB genes encoding for multidrug efflux pumps, but not overall abundance of resistance genes. The observed shifts in microbial community structure and potential function indicate changes in respiration, nutrient cycling, and markers of stress in a stream impacted by UOG waste disposal operations.

Abstract:
Chemical additives used for hydraulic fracturing and matrix acidizing of oil reservoirs were reviewed and priority chemicals of concern needing further environmental risk assessment, treatment demonstration, or evaluation of occupational hazards were identified. We evaluated chemical additives used for well stimulation in California, the third largest oil producing state in the USA, by the mass and frequency of use, as well as toxicity. The most frequently used chemical additives in oil development were gelling agents, cross-linkers, breakers, clay control agents, iron and scale control agents, corrosion inhibitors, biocides, and various impurities and product stabilizers used as part of commercial mixtures. Hydrochloric and hydrofluoric acids, used for matrix acidizing and other purposes, were reported infrequently. A large number and mass of solvents and surface active agents were used, including quaternary ammonia compounds (QACs) and nonionic surfactants. Acute toxicity was evaluated and many chemicals with low hazard to mammals were identified as potentially hazardous to aquatic environments. Based on an analysis of quantities used, toxicity, and lack of adequate hazard evaluation, QACs, biocides, and corrosion inhibitors were identified as priority chemicals of concern that deserve further investigation.

Abstract:

Abstract:
Nearly 70 years old, hydraulic fracturing is a core technique for stimulating hydrocarbon production in a majority of oil and gas reservoirs. Complex fluids are implemented in nearly every step of the fracturing process, most significantly to generate and sustain fractures and transport and distribute proppant particles during and following fluid injection. An extremely wide range of complex fluids are used: naturally occurring polysaccharide and synthetic polymer solutions, aqueous physical and chemical gels, organic gels, micellar surfactant solutions, emulsions, and foams. These fluids are loaded over a wide range of concentrations with particles of varying sizes and aspect ratios and are subjected to extreme mechanical and environmental conditions. We describe the settings of hydraulic fracturing (framed by geology), fracturing mechanics and physics, and the critical role that non-Newtonian fluid dynamics and complex fluids play in the hydraulic fracturing process. Expected final online publication date for the Annual Review of Chemical and Biomolecular Engineering Volume 7 is June 07, 2016. Please see http://www.annualreviews.org/catalog/pubdates.aspx for revised estimates.

Abstract:
Subsurface processes alter the physical and chemical properties of fluid injected for hydraulic fracturing, with implications for its transport and fate in fractured or porous media. Models used to evaluate potential hydraulic fracturing-fluid migration lack formation-specific data to constrain temporal and thermal variation of the physical parameters that govern fluid movement. Density increases of 9.8% and viscosity increases of 26.5% were observed in produced water samples from three horizontally-drilled wells in the Marcellus shale, Pennsylvania, USA over a period of 11 months after hydraulic fracturing. Fluid density and viscosity rapidly increased during the first two weeks after fluid injection because of greater concentrations of dissolved inorganic ions, and plateaued within two months. When experimentally subjected to formation-relevant temperatures, mean density and viscosity decreased by up to 2.7 and 44.4%, respectively, between 20 and 60 degrees C. These measurements yield new data to better constrain constitutive relations in flow and transport models evaluating the migration of hydraulic-fracturing fluid between a wellbore terminus and other subsurface locations. (C) 2015 American Society of Civil Engineers.

Abstract:
Naturally occurring radioactive material (NORM) is a common feature in North Sea oil and gas production offshore but, to date, has been reported from only one production site onshore in the United Kingdom. The latter, Wytch Farm on the Dorset coast, revealed high activity concentrations of 210Pb in metallic form but little evidence of radium accumulation. NORM has now been discovered at two further onshore sites in the East Midlands region of the UK. The material has been characterized in terms of its mineralogy, bulk composition and disequilibrium in the natural uranium and thorium series decay chains. In contrast to Wytch Farm, scale and sludge samples from the East Midlands were found to contain elevated levels of radium and radioactive progeny associated with crystalline strontiobarite. The highest 226Ra and 228Ra activity concentrations found in scale samples were 132 and 60 Bq/g, with mean values of 86 and 40 Bq/g respectively; somewhat higher than the mean for the North Sea and well above national exemption levels for landfill disposal. The two East Midlands sites exhibited similar levels of radioactivity. Scanning electron microscope imaging shows the presence of tabular, idiomorphic and acicular strontiobarite crystals with elemental mapping confirming that barium and strontium are co-located throughout the scale. Bulk compositional data show a corresponding correlation between barium-strontium concentrations and radium activity. Scales and sludge were dated using the 226Ra/210Pb method giving mean ages of 2.2 and 3.7 years, respectively. The results demonstrate clearly that these NORM deposits, with significant radium activity, can form over a very short period of time. Although the production sites studied here are involved in conventional oil recovery, the findings have direct relevance should hydraulic fracturing for shale gas be pursued in the East Midlands oilfield.

Abstract:
Hydraulic fracturing is the process of injecting solutions at high pressure to break apart rock formations and increase efficiency of natural gas extraction. The solutions are recovered and have been land-applied as a disposal technique. The objective of this greenhouse study was to evaluate the effects of inorganic fertilizer, broiler litter, or Milorganite®, and soil depth interval on the growth of Bermuda grass [Cynodon dactylon (L.) Pers] in soil from a site that had been contaminated with fracturing fluid and was devoid of vegetation. In soil from 0–15 cm depth, initial electrical conductivity (ECe), Na, and Cl levels were 14.5 dS/m, 2994 mg/kg, and 5603 mg/kg, respectively. For the 0–30 cm depth, initial ECe, Na, and Cl levels were 14.1 dS/m, 2550 mg/kg, and 5020 mg/kg, respectively. Bermuda grass was sprigged and harvested after nine weeks. Addition of inorganic fertilizer, broiler litter, or Milorganite® resulted in 290, 241, and 172%, respectively, greater shoot biomass compared to unamended soil. Plants grown in the 0–30 cm depth soil had greater root biomass (95%), length (67%), volume (61%), and surface area (65%) compared to those grown in soil from the 0–15 cm depth. Fertilization and cultivation may be useful in revegetating sites contaminated with fracturing fluid.

Abstract:
Growth of the unconventional gas industry is predicted to continue to be an important component of the global energy landscape. The rapid expansion of shale and tight gas development has raised many environmental and human health concerns, particularly in regards to ground and surface water contamination. The unconventional gas industry has begun to transition toward the use of hydraulic fracturing chemicals that pose minimal environmental and human health hazards in order to mitigate the risks associated with possible chemical containment failure. Integrated chemical hazard evaluation has been facilitated by an adapted index-based approach to combine noncommensurate multiparameter chemical hazard data into a single score value. Comparative analysis of existing chemical hazard index scoring systems as well as the formulation of a novel hydraulic fracturing fluid greenness assessment system revealed several important considerations for index development and application. Index scores calculated using the investigated index systems highlighted the need for informed, optimized hazard class selection as input for score determination, the maintenance of hazard category intensity during parameter transformation, as well as representative hazard class and chemical component mathematical weightings, and robust aggregation techniques for final score calculation. Continued research should work to model the combined hazard posed by individual chemicals while considering the effect of dilution as well as incorporate additional index metrics beyond hazard intensity. Fully disclosed index systems, applied with complete knowledge of their strengths and weaknesses, provide useful monitoring and communication tools to promote environmental-best practices in the unconventional gas industry.

Abstract:
During hydraulic fracturing millions of gallons of water are typically injected at high pressure into deep shale formations. This water can be housed in fractures, within the shale matrix, and can potentially migrate beyond the shale formation via fractures and/or faults raising environmental concerns. We describe a generic framework for producing estimates of the volume available in fractures and undamaged shale matrix where water injected into a representative shale site could reside during hydraulic fracturing, and apply it to a representative site that incorporates available field data. The amount of water that can be stored in the fractures is estimated by calculating the volume of all the fractures associated with a discrete fracture network (DFN) based on real data and using probability theory to estimate the volume of smaller fractures that are below the lower cutoff for the fracture radius in the DFN. The amount of water stored in the matrix is estimated utilizing two distinct methods-one using a two-phase model at the pore-scale and the other using a single-phase model at the continuum scale. Based on these calculations, it appears that most of the water resides in the matrix with a lesser amount in the fractures.

Abstract:
Oil and gas extraction and coal-fired electrical power generating stations produce wastewaters that are treated and discharged to rivers in Western Pennsylvania with public drinking water system (PDWS) intakes. Inductively coupled plasma optical emission spectroscopy (ICP-OES) was used to quantify inorganic species in wastewater and river samples using a method based on EPA Method 200.7 rev4.4. A total of 53 emission lines from 30 elements (Al, As, B, Ba, Ca, Cd, Ce, Co, Cr, Cu, Fe, K, Li, Mg, Mn, Mo, Na, Ni, P, Pb, S, Sb, Se, Si, Sn, Sr, Ti, Tl, V, and Zn) were investigated. Samples were prepared by microwave-assisted acid digestion using a mixture of 2% HNO3 and 0.5% HCl. Lower interferences and better detection characteristics resulted in selection of alternative wavelengths for Al, As, Sb, Mg, Mo, and Na. Radial view measurements offered accurate determinations of Al, Ba, K, Li, Na, and Sr in high-brine samples. Spike recovery studies and analyses of reference materials showed 80–105% recoveries for most analytes. This method was used to quantify species in samples with high to low brine concentrations with method detection limits a factor of 2 below the maximum contaminant limit concentrations of national drinking water standards. Elements B, Ca, K, Li, Mg, Na, and Sr were identified as potential tracers for the sources impacting PDWS intakes. Usability of the ICP-OES derived data for factor analytic model applications was also demonstrated.

Abstract:
The rapid development of high-volume horizontal hydraulic fracturing for mining natural gas from shale has posed potential impacts on human health and biodiversity. The produced flow back waters after hydraulic stimulation are known to carry high levels of saline and total dissolved solids. To understand the toxicity and potential carcinogenic effects of these wastewaters, flow back waters from five Marcellus hydraulic fracturing oil and gas wells were analyzed. The physicochemical nature of these samples was analyzed by inductively coupled plasma mass spectrometry and scanning electron microscopy/energy dispersive X-ray spectroscopy. A cytotoxicity study using colony formation as the endpoint was carried out to define the LC50 values of test samples using human bronchial epithelial cells (BEAS-2B). The BEAS-2B cell transformation assay was employed to assess the carcinogenic potential of the samples. Barium and strontium were among the most abundant metals in these samples and the same metals were found to be elevated in BEAS-2B cells after long-term treatment. BEAS-2B cells treated for 6 weeks with flow back waters produced colony formation in soft agar that was concentration dependent. In addition, flow back water-transformed BEAS-2B cells show better migration capability when compared to control cells. This study provides information needed to assess the potential health impact of post-hydraulic fracturing flow back waters from Marcellus Shale natural gas mining.

Abstract:
Managing the wastewater discharged from oil and shale gas fields is a big challenge, because this kind of wastewater is normally polluted by high contents of both oils and salts. Conventional pressure-driven membranes experience little success for treating this wastewater because of either severe membrane fouling or incapability of desalination. In this study, we designed a new nanocomposite forward osmosis (FO) membrane for accomplishing simultaneous oil/water separation and desalination. This nanocomposite FO membrane is composed of an oil-repelling and salt-rejecting hydrogel selective layer on top of a graphene oxide (GO) nanosheets infused polymeric support layer. The hydrogel selective layer demonstrates strong underwater oleophobicity that leads to superior anti-fouling capability under various oil/water emulsions, and the infused GO in support layer can significantly mitigate internal concentration polarization (ICP) through reducing FO membrane structural parameter by as much as 20%. Compared with commercial FO membrane, this new FO membrane demonstrates more than three times higher water flux, higher removals for oil and salts (>99.9% for oil and >99.7% for multivalent ions) and significantly lower fouling tendency when investigated with simulated shale gas wastewater. These combined merits will endorse this new FO membrane with wide applications in treating highly saline and oily wastewaters.

Abstract:
Hydraulically fractured shales are becoming an increasingly important source of natural gas production in the United States. This process has been known to create up to 420 gallons of produced water (PW) per day, but the volume varies depending on the formation, and the characteristics of individual hydraulic fracture. PW from hydraulic fracturing of shales are comprised of injected fracturing fluids and natural formation waters in proportions that change over time. Across the state of Pennsylvania, shale gas production is booming; therefore, it is important to assess the variability in PW chemistry and microbiology across this geographical span. We quantified the inorganic and organic chemical composition and microbial communities in PW samples from 13 shale gas wells in north central Pennsylvania. Microbial abundance was generally low (66–9400 cells/mL). Non-volatile dissolved organic carbon (NVDOC) was high (7–31 mg/L) relative to typical shallow groundwater, and the presence of organic acid anions (e.g., acetate, formate, and pyruvate) indicated microbial activity. Volatile organic compounds (VOCs) were detected in four samples (∼1 to 11.7 μg/L): benzene and toluene in the Burket sample, toluene in two Marcellus samples, and tetrachloroethylene (PCE) in one Marcellus sample. VOCs can be either naturally occurring or from industrial activity, making the source of VOCs unclear. Despite the addition of biocides during hydraulic fracturing, H2S-producing, fermenting, and methanogenic bacteria were cultured from PW samples. The presence of culturable bacteria was not associated with salinity or location; although organic compound concentrations and time in production were correlated with microbial activity. Interestingly, we found that unlike the inorganic chemistry, PW organic chemistry and microbial viability were highly variable across the 13 wells sampled, which can have important implications for the reuse and handling of these fluids.

Abstract:
The ecologically sensitive Susquehanna River Basin (SRB) is an important recharge area and drinking water source for a large population in the northeastern United States. Seasonal road salt application, the presence of regional brines at shallow depths, and produced waters associated with active and legacy conventional Upper Devonian oil and gas wells could increase total dissolved solids (TDS) in groundwater and streams. This study focused on SRB watersheds along the New York/Pennsylvania border, in order to assess current water quality and to establish baseline geochemistry for ground and surface water in a region with potential for increased development of the Marcellus Shale and other unconventional shale gas units. Geochemical composition was determined for 300 stream samples collected from ten sites in four watersheds over variable seasonal flow conditions, and for groundwater from over 500 drinking water wells in this region. Results indicate that many streams and groundwater wells in the study area have elevated TDS levels that indicate pre-existing contributions from saline sources. Dilution of these inputs with fresh water, and the lack of low-level trace element concentrations and isotopic composition in many water quality analyses, highlight the need for alternate robust and sensitive chemical signatures. Comparison with Cl/Br anion ratios and 87Sr/86Sr isotope ratios indicate that the (Ba + Sr)/Mg ratio can be used to discriminate between road salt and regional brine in these cases, and mixing models show that even small additions (0.1–0.01%) of these contaminants can be detected with this cation ratio. The (Ba + Sr)/Mg ratio may be even more sensitive (by an order of magnitude) to incursions of Marcellus Shale produced water, depending on the composition of Marcellus produced waters in this region. This study highlights the need for baseline sampling of freshwater reservoirs and the characterization of potential high TDS sources at a local and regional scale.

Abstract:
Drill cuttings generated during unconventional natural gas extraction from the Marcellus Shale, Appalachian Basin, U.S.A., generally contain a very large component of organic-rich black shale because of extensive lateral drilling into this target unit. In this study, element concentrations and Pb isotope ratios obtained from leached drill cuttings spanning 600 m of stratigraphic section were used to assess the potential for short and long term environmental impacts from Marcellus Shale waste materials, in comparison with material from surrounding formations. Leachates of the units above, below and within the Marcellus Shale yielded Cl/Br ratios of 100–150, similar to produced water values. Leachates from oxidized and unoxidized drill cuttings from the Marcellus Shale contain distinct suites of elevated trace metal concentrations, including Cd, Cu, Mo, Ni, Sb, U, V and Zn. The most elevated Mo, Ni, Sb, U, and V concentrations are found in leachates from the lower portion of the Marcellus Shale, the section typically exploited for natural gas production. In addition, lower 207Pb/206Pb ratios within the lower Marcellus Shale (0.661–0.733) provide a distinctive fingerprint from formations above (0.822–0.846) and below (0.796–0.810), reflecting 206Pb produced as a result of in situ 238U decay within this organic rich black shale. Trace metal concentrations from the Marcellus Shale leachates are similar to total metal concentrations from other black shales. These metal concentrations can exceed screening levels recommended by the EPA, and thus have the potential to impact soil and water quality depending on cuttings disposal methods.

Abstract:
Fluids co-produced with methane from hydraulically fractured organic-rich shales of the Marcellus Formation (USA) are characterized by high total dissolved solids (TDS), including elevated levels of Ba, Sr and Br. To investigate the source and geologic history of these high-TDS fluids and their dissolved constituents, we carried out a series of sequential extraction experiments on dry-drilled cuttings extracted within, below and above the Marcellus Shale from a well in Tioga County, New York State. The experiments were designed to extract (1) water soluble components, (2) exchangeable cations, (3) carbonate minerals, and (4) hydrochloric acid-soluble constituents. The geochemistry of the resultant leachates highlights the different geochemical reservoirs for extractable elements within the shale; notably, Na and Br were largely water-soluble, while Ba was extracted primarily from exchangeable sites, and Ca and Sr were found both in exchangeable sites and carbonate. Strontium isotope ratios measured on the leachates indicate that each of the element reservoirs has a distinct value. Measured 87Sr/86Sr ratios in the water soluble component are similar to those of Marcellus produced water, while the ion exchange reservoir yields lower ratios, and carbonate Sr is lower still, approaching Devonian-Silurian seawater values. Despite the isotopic similarity of water leachates and produced water, the total water chemistry argues against generation of produced water by interaction of hydraulic fracturing fluid with “dry” shale. The high-TDS produced water is most likely trapped formation water (within and/or adjacent to the shale) that is released by hydraulic fracturing. The formation water was affected by multiple processes, possibly including basin scale, tectonically-driven fluid flow. Significant chemical and isotopic differences between Marcellus Shale produced water and overlying Upper Devonian/Lower Mississippian produced waters suggests a hydrologic barrier has been maintained in parts of the Appalachian Basin since the late Paleozoic.

Abstract:
Development of unconventional shale gas wells can generate significant quantities of drilling waste, including trace metal-rich black shale from the lateral portion of the drillhole. We carried out sequential extractions on 15 samples of dry-drilled cuttings and core material from the gas-producing Middle Devonian Marcellus Shale and surrounding units to identify the host phases and evaluate the mobility of selected trace elements during cuttings disposal. Maximum whole rock concentrations of uranium (U), arsenic (As), and barium (Ba) were 47, 90, and 3333 mg kg−1, respectively. Sequential chemical extractions suggest that although silicate minerals are the primary host for U, as much as 20% can be present in carbonate minerals. Up to 74% of the Ba in shale was extracted from exchangeable sites in the shale, while As is primarily associated with organic matter and sulfide minerals that could be mobilized by oxidation. For comparison, U and As concentrations were also measured in 43 produced water samples returned from Marcellus Shale gas wells. Low U concentrations in produced water (<0.084–3.26 μg L−1) are consistent with low-oxygen conditions in the wellbore, in which U would be in its reduced, immobile form. Arsenic was below detection in all produced water samples, which is also consistent with reducing conditions in the wellbore minimizing oxidation of As-bearing sulfide minerals. Geochemical modeling to determine mobility under surface storage and disposal conditions indicates that oxidation and/or dissolution of U-bearing minerals in drill cuttings would likely be followed by immobilization of U in secondary minerals such as schoepite, uranophane, and soddyite, or uraninite as conditions become more reducing. Oxidative dissolution of arsenic containing sulfides could release soluble As in arsenate form under oxic acidic conditions. The degree to which the As is subsequently immobilized depends on the redox conditions along the landfill flow path. The results suggest that proper management of drill cuttings can minimize mobilization of these metals by monitoring and controlling Eh, pH and dissolved constituents in landfill leachates.

Abstract:
The Middle Devonian age Marcellus Shale contains one of the largest shale gas plays in North America. Hydrocarbon production in the eastern part of the play is mostly “dry gas,” consisting of essentially pure methane. Production of natural gas liquids (condensate) increases toward the west, which is the area currently, being targeted by developers. Two Marcellus Shale cores from West Virginia were analyzed to compare the isotopic and geochemical characteristics of a liquids-prone well (WV-7) in Wetzel County with a gas-prone well (WV-6) in Monongalia County. The contrasts between the cores indicate that the conditions of the Marcellus Shale deposition were different between the two sites. The dominant organic matter preserved in each core is isotopically different; δ13Corg values are lighter on average in WV-6 compared with WV-7. A possible explanation is that a larger fraction of terrestrial organic matter was preserved in the WV-6 core, whereas WV-7 may contain a greater percentage of marine organic matter. Clastic-influx proxies (e.g. Ti/Al, Ca/Al and Mg/Al) also suggest that the WV-6 core site received a higher siliciclastic input compared to WV-7, consistent with a more proximal location to dry land and the delivery of greater amounts of terrestrial organic matter. Depleted δ13Ccarb values, low concentrations of redox sensitive elements (e.g. V, Cr, Ni and U), and high variability δ15N values in the WV-6 core all suggest the presence of higher dissolved oxygen concentration and short term shifts in an oxic/anoxic boundary near the sediment–water interface during deposition. These lines of evidence indicate that the depositional conditions were favorable for the accumulation of predominantly gas-prone Type III kerogen in the Marcellus Shale at the WV-6 site. In contrast, the Marcellus Shale at the WV-7 site was deposited in a more distal area that received a low terrestrial sediment supply, organic matter primarily derived from marine algae, and bottom water conditions that were dominantly anoxic. Such conditions were favorable for the accumulation of Type II kerogen that has a greater capacity to generate liquid hydrocarbons. Differences between the liquids-prone and gas-prone parts of the Marcellus Shale play have been largely ascribed to depth-of-burial and thermal maturation history; this study indicates that depositional environment and sedimentary facies may have played significant roles as well.

Abstract:
Hydraulic fracturing of shale for gas production in Pennsylvania generates large quantities of wastewater, the composition of which has been inadequately characterized. We compiled a unique data set from state-required wastewater generator reports filed in 2009?2011. The resulting data set, comprising 160 samples of flowback, produced water, and drilling wastes, analyzed for 84 different chemicals, is the most comprehensive available to date for Marcellus Shale wastewater. We analyzed the data set using the Kaplan?Meier method to deal with the high prevalence of nondetects for some analytes, and compared wastewater characteristics with permitted effluent limits and ambient monitoring limits and capacity. Major-ion concentrations suggested that most wastewater samples originated from dilution of brines, although some of our samples were more concentrated than any Marcellus brines previously reported. One problematic aspect of this wastewater was the very high concentrations of soluble constituents such as chloride, which are poorly removed by wastewater treatment plants; the vast majority of samples exceeded relevant water quality thresholds, generally by 2?3 orders of magnitude. We also examine the capacity of regional regulatory monitoring to assess and control these risks.

Abstract:
Volumes of natural gas extraction-derived wastewaters have increased sharply over the past decade, but the ultimate fate of those waste streams is poorly characterized. Here, we sought to (a) quantify natural gas residual fluid sources and endpoints to bound the scope of potential waste stream impacts and (b) describe the organic pollutants discharged to surface waters following treatment, a route of likely ecological exposure. Our findings indicate that centralized waste treatment facilities (CWTF) received 9.5% (8.5 ? 108 L) of natural gas residual fluids in 2013, with some facilities discharging all effluent to surface waters. In dry months, discharged water volumes were on the order of the receiving body flows for some plants, indicating that surface waters can become waste-dominated in summer. As disclosed organic compounds used in high volume hydraulic fracturing (HVHF) vary greatly in physicochemical properties, we deployed a suite of analytical techniques to characterize CWTF effluents, covering 90.5% of disclosed compounds. Results revealed that, of nearly 1000 disclosed organic compounds used in HVHF, only petroleum distillates and alcohol polyethoxylates were present. Few analytes targeted by regulatory agencies (e.g., benzene or toluene) were observed, highlighting the need for expanded and improved monitoring efforts at CWTFs.

Abstract:
Due to the rapid expansion in hydraulic fracturing (fracking), there is a need for robust, portable and specific water analysis techniques. Early detection of contamination is crucial for the prevention of lasting environmental damage. Bromide can potentially function as an early indicator of water contamination by fracking waste, because there is a high concentration of bromide ions in fracking wastewaters. To facilitate this, a microfluidic paper-based analytical device (μPAD) has been developed and optimized for the quantitative colorimetric detection of bromide in water using a smartphone. A paper microfluidic platform offers the advantages of inexpensive fabrication, elimination of unstable wet reagents, portability and high adaptability for widespread distribution. These features make this assay an attractive option for a new field test for on-site determination of bromide.

Abstract:
Natural gas extraction from Marcellus Shale generates large quantities of flowback water that contain high levels of salinity, heavy metals, and Naturally Occurring Radioactive Material (NORM). This water is typically stored in centralized storage impoundments or tanks prior to reuse, treatment or disposal. The fate of Ra-226, which is the dominant NORM component in flowback water, in three centralized storage impoundments in southwestern Pennsylvania was investigated during a 2.5-year period. Field sampling revealed that Ra-226 concentration in these storage facilities depends on the management strategy but is generally increasing during the reuse of flowback water for hydraulic fracturing. In addition, Ra-226 is enriched in the bottom solids (e.g., impoundment sludge) where it increased from less than 10 pCi/g for fresh sludge to several hundred pCi/g for aged sludge. A combination of sequential extraction procedure (SEP) and chemical composition analysis of impoundment sludge revealed that barite is the main carrier of Ra-226 in the sludge. Toxicity characteristic leaching procedure (TCLP) (EPA Method 1311) was used to assess the leaching behavior of Ra-226 in the impoundment sludge and its implications for waste management strategies for this low-level radioactive solid waste. Radiation exposure for on-site workers calculated using the RESRAD model showed that the radiation dose equivalent for the baseline conditions was well below the NRC limit for the general public.

Abstract:
The chemical additives used in fracturing fluids can be used as tracers of water contamination caused by hydraulic fracturing operations. For this purpose, a complete chemical characterization is necessary using advanced analytical techniques. Liquid chromatography coupled with quadrupole time-of-flight mass spectrometry (LC/Q-TOF-MS) was used to identify chemical additives present in flowback and produced waters. Accurate mass measurements of main ions and fragments were used to characterize the major components of fracking fluids. Sodium adducts turned out to be the main molecular adduct ions detected for some additives due to oxygen-rich structures. Among the classes of chemical components analyzed by mass spectrometry include gels (guar gum), biocides (glutaraldehyde and alkyl dimethyl benzyl ammonium chloride), and surfactants (cocamidopropyl dimethylamines, cocamidopropyl hydroxysultaines, and cocamidopropyl derivatives). The capabilities of accurate mass and MS-MS fragmentation are explored for the unequivocal identification of these compounds. A special emphasis is given to the mass spectrometry elucidation approaches used to identify a major class of hydraulic fracturing compounds, surfactants.

Abstract:
Little is known of the attenuation of chemical mixtures created for hydraulic fracturing within the natural environment. A synthetic hydraulic fracturing fluid was developed from disclosed industry formulas and produced for laboratory experiments using commercial additives in use by Marcellus shale field crews. The experiments employed an internationally accepted standard method (OECD 301A) to evaluate aerobic biodegradation potential of the fluid mixture by monitoring the removal of dissolved organic carbon (DOC) from an aqueous solution by activated sludge and lake water microbial consortia for two substrate concentrations and four salinities. Microbial degradation removed from 57 % to more than 90 % of added DOC within 6.5 days, with higher removal efficiency at more dilute concentrations and little difference in overall removal extent between sludge and lake microbe treatments. The alcohols isopropanol and octanol were degraded to levels below detection limits while the solvent acetone accumulated in biological treatments through time. Salinity concentrations of 40 g/L or more completely inhibited degradation during the first 6.5 days of incubation with the synthetic hydraulic fracturing fluid even though communities were pre-acclimated to salt. Initially diverse microbial communities became dominated by 16S rRNA sequences affiliated with Pseudomonas and other Pseudomonadaceae after incubation with the synthetic fracturing fluid, taxa which may be involved in acetone production. These data expand our understanding of constraints on the biodegradation potential of organic compounds in hydraulic fracturing fluids under aerobic conditions in the event that they are accidentally released to surface waters and shallow soils.

Abstract:
Environmental context There is growing worldwide interest in the production of oil and gas from deep, shale formations following advances in the technical expertise to exploit these resources such as hydraulic fracturing (fracking). The potential widespread application of hydraulic fracturing has raised concerns over deleterious environmental impacts on fragile water resources. We discuss the environmental management challenges faced by the oil and gas industry, and the opportunities for innovation in the industry. Abstract The need for cheap and readily available energy and chemical feedstock, and the desire for energy independence have spurred worldwide interest in the development of unconventional oil and gas resources; in particular, the production of oil and gas from shale formations. Although these resources have been known for a long time, the technical expertise and market forces that enable economical development has coincided over the last 15 years. The amalgamation of horizontal drilling and hydraulic fracturing have enabled favourable economics for development of fossil energy from these unconventional reservoirs, but their potential widespread application has raised concerns over deleterious environmental impacts on fragile water resources. The environmental management challenges faced by the oil and gas industry arise from local water availability and infrastructure for treating and disposing of the high-strength wastewater that is produced. Although there are significant challenges, these create opportunities for innovation in the industry.

Abstract:
Hydraulic fracturing (HF) has been used with horizontal drilling to extract gas and natural gas liquids from source rock such as the Marcellus Shale in the Appalachian Basin. Horizontal drilling and HF generates large volumes of waste water known as flowback. While inorganic ion chemistry has been well characterized, and the general increase in concentration through the flowback is widely recognized, the literature contains little information relative to organic compounds and radionuclides. This study examined the chemical evolution of liquid process and waste streams (including makeup water, HF fluids, and flowback) in four Marcellus Shale gas well sites in north central West Virginia. Concentrations of organic and inorganic constituents and radioactive isotopes were measured to determine changes in waste water chemistry during shale gas development. We found that additives used in fracturing fluid may contribute to some of the constituents (e.g., Fe) found in flowback, but they appear to play a minor role. Time sequence samples collected during flowback indicated increasing concentrations of organic, inorganic and radioactive constituents. Nearly all constituents were found in much higher concentrations in flowback water than in injected HF fluids suggesting that the bulk of constituents originate in the Marcellus Shale formation rather than in the formulation of the injected HF fluids. Liquid wastes such as flowback and produced water, are largely recycled for subsequent fracturing operations. These practices limit environmental exposure to flowback.

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A suite of analytical tools was applied to thoroughly analyze the chemical composition of an oil/gas well flowback water from the Denver–Julesburg (DJ) basin in Colorado, and the water quality data was translated to propose effective treatment solutions tailored to specific reuse goals. Analysis included bulk quality parameters, trace organic and inorganic constituents, and organic matter characterization. The flowback sample contained salts (TDS = 22,500 mg/L), metals (e.g., iron at 81.4 mg/L) and high concentration of dissolved organic matter (DOC = 590 mgC/L). The organic matter comprised fracturing fluid additives such as surfactants (e.g., linear alkyl ethoxylates) and high levels of acetic acid (an additives' degradation product), indicating the anthropogenic impact on this wastewater. Based on the water quality results and preliminary treatability tests, the removal of suspended solids and iron by aeration/precipitation (and/or filtration) followed by disinfection was identified as appropriate for flowback recycling in future fracturing operations. In addition to these treatments, a biological treatment (to remove dissolved organic matter) followed by reverse osmosis desalination was determined to be necessary to attain water quality standards appropriate for other water reuse options (e.g., crop irrigation). The study provides a framework for evaluating site-specific hydraulic fracturing wastewaters, proposing a suite of analytical methods for characterization, and a process for guiding the choice of a tailored treatment approach.

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Treatment of produced water, i.e. wastewater from hydraulic fracturing, for reuse or final disposal is challenged by both high salinity and the presence of organic compounds. Organic compounds in produced water may foul physical-chemical treatment processes, or support microbial corrosion, fouling, and sulfide release. Biological approaches have potential applications in produced water treatment, including reducing fouling of physical-chemical treatment processes and decreasing biological activity during produced water holding; however, conventional activated sludge treatments are intolerant of high salinity. In this study, a biofilm treatment approach using constructed microbial mats was evaluated for biodegradation performance, microbial community structure, and metabolic potential in both simulated and real produced water. Results demonstrated that engineered microbial mats are active at total dissolved solids (TDS) concentrations up to at least 100,000 mg/L, and experiments in real produced water showed a biodegradation capacity of 1.45 mg COD/gramwet-day at a TDS concentration of 91,351 mg/L. Additionally, microbial community and metagenomic analyses revealed an adaptive microbial community that shifted based upon the sample being treated and has the metabolic potential to degrade a wide array of contaminants, suggesting the potential of this approach to treat produced waters with varying composition.

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Elevated concentration of naturally occurring radioactive material (NORM) in wastewater generated from Marcellus Shale gas extraction is of great concern due to potential environmental and public health impacts. Development of a rapid and robust method for analysis of Ra-226, which is the major NORM component in this water, is critical for the selection of appropriate management approaches to properly address regulatory and public concerns. Traditional methods for Ra-226 determination require long sample holding time or long detection time. A novel method combining Inductively Coupled Mass Spectrometry (ICP-MS) with solid-phase extraction (SPE) to separate and purify radium isotopes from the matrix elements in high salinity solutions is developed in this study. This method reduces analysis time while maintaining requisite precision and detection limit. Radium separation is accomplished using a combination of a strong-acid cation exchange resin to separate barium and radium from other ions in the solution and a strontium-specific resin to isolate radium from barium and obtain a sample suitable for analysis by ICP-MS. Method optimization achieved high radium recovery (101±6% for standard mode and 97±7% for collision mode) for synthetic Marcellus Shale wastewater (MSW) samples with total dissolved solids as high as 171,000 mg/L. Ra-226 concentration in actual MSW samples with TDS as high as 415,000 mg/L measured using ICP-MS matched very well with the results from gamma spectrometry. The Ra-226 analysis method developed in this study requires several hours for sample preparation and several minutes for analysis with the detection limit of 100 pCi/L with RSD of 45% (standard mode) and 67% (collision mode). The RSD decreased to below 15% when Ra-226 concentration increased over 500 pCi/L.

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Flowback and produced wastewaters from unconventional hydraulic fracturing during oil and gas explorations typically brings to the surface Naturally Occurring Radioactive Materials (NORM), predominantly radioisotopes from the U238 and Th232 decay chains. Traditionally, radiological sampling are performed by sending collected small samples for laboratory tests either by radiochemical analysis or measurements by a high-resolution High-Purity Germanium (HPGe) gamma spectrometer. One of the main isotopes of concern is Ra226 which requires an extended 21-days quantification period to allow for full secular equilibrium to be established for the alpha counting of its progeny daughter Rn222. Field trials of a sodium iodide (NaI) scintillation detector offers a more economic solution for rapid screenings of radiological samples. To achieve the quantification accuracy, this gamma spectrometer must be efficiency calibrated with known standard sources prior to field deployments to analyze the radioactivity concentrations in hydraulic fracturing waste products.

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The number of Marcellus Shale gas wells drilled in the Appalachian basin has increased rapidly over the past decade, leading to increased interest in the highly saline water produced with the natural gas which must be recycled, treated, or injected into deep disposal wells. New geochemical and isotopic analyses of produced water for 3 time-series and 13 grab samples from Marcellus Shale gas wells in southwest and north central Pennsylvania (PA) are used to address the origin of the water and solutes produced over the long term (>12 months). The question of whether the produced water originated within the Marcellus Shale, or whether it may have been drawn from adjacent reservoirs via fractures is addressed using measurements of and activity. These parameters indicate that the water originated in the Marcellus Shale, and can be more broadly used to trace water of Marcellus Shale origin. During the first 1–2 weeks of production, rapid increases in salinity and positive shifts in values were observed in the produced water, followed by more gradual changes until a compositional plateau was reached within approximately 1 yr. The values and relationships between Na, Cl, and Br provide evidence that the water produced after compositional stabilization is natural formation water, the salinity for which originated primarily from evaporatively concentrated paleoseawater. The rapid transition from injected water to chemically and isotopically distinct water while of the injected water volume had been recovered, supports the hypothesis that significant volumes of injected water were removed from circulation by imbibition.

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Hydraulic fracturing fluids contain a mix of organic and inorganic additives in an aqueous media. The compositions of these mixtures vary according to the region or company use, thus making the process of identifying individual compounds difficult. The analytical characterization of such mixtures is important in order to understand the transport, environmental fate and ultimate potential health impact in various water compartments associated with hydraulic fracturing. Organic compound classes include solvents, gels, biocides, scale inhibitors, friction reducers, surfactants and other related compounds. These contaminants are usually present in trace amounts, so sophisticated analytical methodologies are needed in order to fully characterize the chemical composition of fracking fluids. The current state of knowledge of chemical components and approaches for their analysis is reviewed here. In recent years, modern analytical methodologies, such as gas chromatography–mass spectrometry (GC–MS) have been specifically used to identify organic chemical components of fracking fluids and/or flowback and produced waters associated with the process of hydraulic fracturing. Other techniques such as liquid chromatography–mass spectrometry (LC–MS) have not been explored in detail yet. In this review a detailed description of chemical constituents present in hydraulic fracturing waters will be given, as well as an evaluation of the analytical techniques used for their unequivocal determination.

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The expansion of unconventional shale gas and hydraulic fracturing has increased the volume of the oil and gas wastewater (OGW) generated in the U.S. Here we demonstrate that OGW from Marcellus and Fayetteville hydraulic fracturing flowback fluids and Appalachian conventional produced waters is characterized by high chloride, bromide, iodide (up to 56 mg/L), and ammonium (up to 420 mg/L). Br/Cl ratios were consistent for all Appalachian brines, which reflect an origin from a common parent brine, while the I/Cl and NH4/Cl ratios varied among brines from different geological formations, reflecting geogenic processes. There were no differences in halides and ammonium concentrations between OGW originating from hydraulic fracturing and conventional oil and gas operations. Analysis of discharged effluents from three brine treatment sites in Pennsylvania and a spill site in West Virginia show elevated levels of halides (iodide up to 28 mg/L) and ammonium (12 to 106 mg/L) that mimic the composition of OGW and mix conservatively in downstream surface waters. Bromide, iodide, and ammonium in surface waters can impact stream ecosystems and promote the formation of toxic brominated-, iodinated-, and nitrogen disinfection byproducts during chlorination at downstream drinking water treatment plants. Our findings indicate that discharge and accidental spills of OGW to waterways pose risks to both human health and the environment.

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Biocides are critical components of hydraulic fracturing ("fracking") fluids used for unconventional shale gas development. Bacteria may cause bioclogging and inhibit gas extraction, produce toxic hydrogen sulfide, and induce corrosion leading to downhole equipment failure. The use of biocides such as glutaraldehyde and quaternary ammonium compounds has spurred a public concern and debate among regulators regarding the impact of inadvertent releases into the environment on ecosystem and human health. This work provides a critical review of the potential fate and toxicity of biocides used in hydraulic fracturing operations. We identified the following physicochemical and toxicological aspects as well as knowledge gaps that should be considered when selecting biocides: (1) uncharged species will dominate in the aqueous phase and be subject to degradation and transport whereas charged species will sorb to soils and be less bioavailable; (2) many biocides are short-lived or degradable through abiotic and biotic processes, but some may transform into more toxic or persistent compounds; (3) understanding of biocides' fate under downhole conditions (high pressure, temperature, and salt and organic matter concentrations) is limited; (4) several biocidal alternatives exist, but high cost, high energy demands, and/or formation of disinfection byproducts limits their use. This review may serve as a guide for environmental risk assessment and identification of microbial control strategies to help develop a sustainable path for managing hydraulic fracturing fluids.

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The objective of the present study was to investigate the feasibility of stretching an arc discharge in produced water to increase the volume of produced water treated by plasma. Produced water is the wastewater generated by hydraulic fracturing of shale during the production phase in shale-oil or shale-gas exploration. The electric conductivity of produced water is in the range of 50-200 mS/cm, which provides both a challenge and opportunity for the application of plasmas. Stretching of an arc discharge in produced water was accomplished using a ground electrode and two high-voltage electrodes: one positioned close to the ground electrode and the other positioned farther away from the ground. The benefit of stretching the arc is that the contact between the arc and water is significantly increased, resulting in more efficient plasma treatment in both performance and energy cost.

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Hydraulic fracturing fluids are chemical mixtures used to enhance oil and gas extraction. There are concerns that fracturing fluids are hazardous and that their release into the environment - by direct injection to coal and shale formations or as residue in produced water - may have effects on ecosystems, water quality and public health. This study aimed to characterise the acute cytotoxicity of a hydraulic fracturing fluid using a human gastrointestinal cell line and, using this data, contribute to the understanding of potential human health risks posed by coal seam gas (CSG) extraction in Queensland, Australia. Previous published research on the health effects of hydraulic fracturing fluids has been limited to desktop studies of individual chemicals. As such, this study is one of the first attempts to characterise the toxicity of a hydraulic fracturing mixture using laboratory methods. The fracturing fluid was determined to be cytotoxic, with half maximal inhibitory concentrations (IC50) values across mixture variations ranging between 25 and 51 mM. When used by industry, these fracturing fluids would be at concentrations of over 200 mM before injection into the coal seam. A 5-fold dilution would be sufficient to reduce the toxicity of the fluids to below the detection limit of the assay. It is unlikely that human exposure would occur at these high ('before use') concentrations and likely that the fluids would be diluted during use. Thus, it can be inferred that the level of acute risk to human health associated with the use of these fracturing fluids is low. However, a thorough exposure assessment and additional chronic and targeted toxicity assessments are required to conclusively determine human health risks.

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The reuse of produced water generated by natural gas extraction from Marcellus Shale for hydraulic fracturing is the dominant management option in Pennsylvania (PA), USA. The advantages and disadvantages of this management approach are reviewed and discussed together with long-term concerns and technology development needs. Abandoned mine drainage is a promising alternative make-up water, but high sulfate concentrations will lead to barite precipitation once it is mixed with the produced water. Bench-scale studies were conducted to optimize barite separation from this mixture that meets the finished water quality criteria for sulfate. Conventional separation processes are very effective in removing these solids but radium (Ra) co-precipitation may be a concern for their disposal in municipal landfills. If the produced water volume exceeds the reuse capacity for hydraulic fracturing, lime–soda ash softening can be used to remove divalent cations, including radium, to enable the production of pure salts using subsequent thermal processes.

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Electrocoagulation has been used to remove solids and some metals from both water and wastewater sources for decades. Additionally, chemical softening is commonly employed in water treatment systems to remove hardness. This paper assesses the combination and sequence of softening and EC methods to treat hydraulic fracturing flowback and produced water from shale oil and gas operations. EC is one of the available technologies to treat produced water for reuse in frac fluids, eliminating not only the need to transport more water but also the costs of providing fresh water. In this paper, the influence of chemical softening on EC was studied. In the softening process, pH was raised to 9.5 and 10.2 before and after EC, respectively. Softening, when practiced before EC was more effective for removing turbidity with samples from wells older than one month (99% versus 88%). However, neither method was successful in treating samples collected from early flowback (1-day and 2-day samples), likely due to the high concentration of organic matter. For total organic carbon, hardness, Ba, Sr, and B removal, application of softening before EC appeared to be the most efficient approach, likely due to the formation of solids before the coagulation process.

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Economic production from tight sand gas reservoirs usually involves multistage hydraulic fracturing. High costs of water acquisition and waste water disposal, and the lack of available water resources near operation sites, make the reuse of produced water an unavoidable option. However, recycling produced water in hydraulic fracturing jobs result in low quality fracturing fluids, which usually have high levels of hardness and salinity. This is especially true for flowback fluids, which contain high polymer loading. The viscosity and rheological properties of fracturing fluids significantly affect leak-off rate, proppant placement, length and width of fractures, fracture conductivity, and consequently, the success of the treatment. The objective of this study is to determine the acceptable dissolved solid contents for flowback fluids to prepare fracturing fluids. Analyses of 36 flowback fluid samples from the West Texas region were collected, and experimental studies were conducted on the analysis of the dissolved solids of produced water, which affect the application of flowback fluids and the capability of prepared fluids in proppant transport and handling. A high-pH borate crosslinked guar-based polymer was selected to determine the ranges of acceptable salt contents. Dynamic viscosity and rheological properties tests, static proppant settling, and small-amplitude oscillation rheology were the methods used to evaluate prepared samples at low, medium, and high temperatures up to 305 °F (152 °C). Some divalent cations such as calcium and magnesium have negative effects on the prepared polymers. Magnesium is the controlling ion, and approximately 30% of flowback fluids must be treated to meet the maximum acceptable concentration criterion. While monovalent cations such as sodium and potassium were tolerable at higher concentrations and the potassium contents in almost all flowback fluids met the determined acceptable value, more than 40% of samples required treatment for high sodium ion concentrations. Although the presence of other ions such as iron shows no significant variation in fracturing fluid properties, they can affect treatment in special cases. Adjusting the concentrations of the polymer, buffer, and crosslinker can minimize the adverse effects of temperature and salts. The fluids prepared with the determined ranges of dissolved solids showed reasonable thermal stability and proppant transport characteristics. This paper introduces the practical operating range for produced water composition and defines the ions that can adversely impact borate-crosslinked fracturing fluid characteristics at different temperatures.

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The rapid development of unconventional oil and gas production has generated large amounts of wastewater for disposal, raising significant environmental and public health concerns. Treatment and beneficial use of produced water presents many challenges due to its high concentrations of petroleum hydrocarbons and salinity. The objectives of this study were to investigate the feasibility of treating actual shale gas produced water using a bioelectrochemical system integrated with capacitive deionization-a microbial capacitive desalination cell (MCDC). Microbial degradation of organic compounds in the anode generated an electric potential that drove the desalination of produced water. Sorption and biodegradation resulted in a combined organic removal rate of 6.4mg dissolved organic carbon per hour in the reactor, and the MCDC removed 36mg salt per gram of carbon electrode per hour from produced water. This study is a proof-of-concept that the MCDC can be used to combine organic degradation with desalination of contaminated water without external energy input.

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Microbial activity in produced water from hydraulic fracturing operations can lead to undesired environmental impacts and increase gas production costs. However, the metabolic profile of these microbial communities is not well understood. Here, for the first time, we present results from a shotgun metagenome of microbial communities in both hydraulic fracturing source water and wastewater produced by hydraulic fracturing. Taxonomic analyses showed an increase in anaerobic/facultative anaerobic classes related to Clostridia, Gammaproteobacteria, Bacteroidia and Epsilonproteobacteria in produced water as compared to predominantly aerobic Alphaproteobacteria in the fracturing source water. The metabolic profile revealed a relative increase in genes responsible for carbohydrate metabolism, respiration, sporulation and dormancy, iron acquisition and metabolism, stress response and sulfur metabolism in the produced water samples. These results suggest that microbial communities in produced water have an increased genetic ability to handle stress, which has significant implications for produced water management, such as disinfection.

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A detailed analysis is reported of the organic composition of produced water samples from typical shale gas wells in the Marcellus (PA), Eagle Ford (TX), and Barnett (NM) formations. The quality of shale gas produced (and frac flowback) waters is a current environmental concern and disposal problem for producers. Re-use of produced water for hydraulic fracturing is being encouraged; however, knowledge of the organic impurities is important in determining the method of treatment. The metal content was determined by inductively coupled plasma optical emission spectrometry (ICP-OES). Mineral elements are expected depending on the reservoir geology and salts used in hydraulic fracturing; however, significant levels of other transition metals and heavier main group elements are observed. The presence of scaling elements (Ca and Ba) is related to the pH of the water rather than total dissolved solids (TDS). Using gas chromatography mass spectrometry (GC/MS) analysis of the chloroform extracts of the produced water samples, a plethora of organic compounds were identified. In each water sample, the majority of organics are saturated (aliphatic), and only a small fraction comes under aromatic, resin, and asphaltene categories. Unlike coalbed methane produced water it appears that shale oil/gas produced water does not contain significant quantities of polyaromatic hydrocarbons reducing the potential health hazard. Marcellus and Barnett produced waters contain predominantly C6–C16 hydrocarbons, while the Eagle Ford produced water shows the highest concentration in the C17–C30 range. The structures of the saturated hydrocarbons identified generally follows the trend of linear > branched > cyclic. Heterocyclic compounds are identified with the largest fraction being fatty alcohols, esters, and ethers. However, the presence of various fatty acid phthalate esters in the Barnett and Marcellus produced waters can be related to their use in drilling fluids and breaker additives rather than their presence in connate fluids. Halogen containing compounds are found in each of the water samples, and although the fluorocarbon compounds identified are used as tracers, the presence of chlorocarbons and organobromides formed as a consequence of using chlorine containing oxidants (to remove bacteria from source water), suggests that industry should concentrate on non-chemical treatments of frac and produced waters.

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Two series of ethylene oxide (EO) surfactants, polyethylene glycols (PEGs from EO3 to EO33) and linear alkyl ethoxylates (LAEs C-9 to C-15 with EO3 to EO28), were identified in hydraulic fracturing flowback and produced water using a new application of the Kendrick mass defect and liquid chromatography/quadrupole-time-of-flight mass spectrometry. The Kendrick mass defect differentiates the proton, ammonium, and sodium adducts in both singly- and doubly-charged forms. A structural model of adduct formation is presented and binding constants are calculated, which is based on a spherical cage-like conformation, where the central cation ( NH4+ or Na+) is coordinated with ether oxygens. A major purpose of the study was the identification of the ethylene oxide (EO) surfactants and the construction of a database with accurate masses and retention times in order to unravel the mass spectral complexity of surfactant mixtures used in hydraulic fracturing fluids. For example, over five hundred accurate mass assignments are made in a few seconds of computer time, which then is used as a fingerprint chromatogram of the water samples. This technique is applied to a series of flowback and produced water samples to illustrate the usefulness of ethoxylate ?fingerprinting?, in a first application to monitor water quality that results from fluids used in hydraulic fracturing.

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Hydraulic fracturing has been used by the oil and gas industry as a way to boost hydrocarbon production since 1947. Recent advances in fracturing technologies, such as multistage fracturing in horizontal wells, are responsible for the latest hydrocarbon production boom in the US. Linear or crosslinked guars are the most commonly used fluids in traditional fracturing operations. The main functions of these fluids are to open/propagate the fractures and transport proppants into the fractures. Proppants are usually applied to form a thin layer between fracture faces to prop the fractures open at the end of the fracturing process. Chemical breakers are used to break the polymers at the end of the fracturing process so as to provide highly conductive fractures. Concerns over fracture conductivity damage by viscous fluids in ultra-tight formations found in unconventional reservoirs prompted the industry to develop an alternative fracturing fluid called “slickwater”. It consists mainly of water with a very low concentration of linear polymer. The low concentration polymer serves primarily to reduce the friction loss along the flow lines. Proppant-carrying capability of this type of fluids is still a subject of debate among industry experts. Constraints on local water availability and the potential for damage to formations have led the industry to develop other types of fracturing fluids such as viscoelastic surfactants and energized fluids. This article reviews both the traditional viscous fluids used in conventional hydraulic fracturing operations as well as the new family of fluids being developed for both traditional and unconventional reservoirs. © 2014 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2014, 131, 40735.

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Flowback water is the solution that returns to the surface following completion of the hydraulic fracturing process during natural gas extraction. This study examines and analyzes the constituents that make up flowback waters collected from various drilling sites in Marcellus shale formation in the states of Pennsylvania, New York, and West Virginia. Flowback sampling data were collected from four different sources (the Environmental Protection Agency, Gas Technology Institute; Pennsylvania Department of Environmental Protection; Bureau of Oil and Gas Management; and the New York Department of Environmental Conservation) and compiled into one database with a total of 35,000 entries. Descriptive statistical analysis revealed high concentrations of chlorinated solvents, disinfectants, dissolved metals, organic compounds, radionuclides, and total dissolved solids. A one-way ANOVA test revealed that over 60% of the constituents tested displayed significant differences (significance level=0.05) in mean concentrations among the four data sources. Relative prioritization scores were developed for 58 constituents by dividing observed mean concentrations by the maximum contamination level (MCL) guidelines for drinking water. The following constituents were found to have mean concentrations over 10 times greater than the MCL: 1,2-dichloroethane, antimony, barium, benzene, benzo(a)pyrene, chloride, dibromochloromethane, gross alpha, iron, manganese, pentachlorophenol, radium, thallium, and vinyl chloride. Concentrations of anthropogenic chemicals are tightly correlated with each other, but not with chloride concentrations, and not with naturally occurring inorganics and radionuclides.