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Organic Chemical Characterization and Mass Balance of a Hydraulically Fractured Well: From Fracturing Fluid to Produced Water Over 405 Days James S. Rosenblum, E. Michael Thurman, Imma Ferrer, George R. Aiken, and Karl G. Linden Environ. Sci. Technol., Just Accepted Manuscript • DOI: 10.1021/acs.est.7b03362 • Publication Date (Web): 14 Nov 2017 Downloaded from http://pubs.acs.org on November 17, 2017

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Environmental Science & Technology

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Organic Chemical Characterization and Mass Balance of a Hydraulically Fractured

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Well: From Fracturing Fluid to Produced Water Over 405 Days

3 4

James Rosenbluma, E. Michael Thurmanb, Imma Ferrerb, George Aikenc, and Karl G.

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Lindena*

6 7

a

8

Colorado, UCB 428, Boulder, CO 80309, United States

9

b

Department of Civil, Environmental, and Architectural Engineering, University of

Center for Environmental Mass Spectrometry, University of Colorado, UCB 428,

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Boulder, CO 80309, United States

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c

U.S. Geological Survey, Boulder, Colorado, 80309, United States

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*Corresponding author: [email protected]

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Abstract

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A long-term field study (405 days) of a hydraulically fractured well from the Niobrara

17

Formation in the Denver-Julesburg Basin was completed. Characterization of organic

18

chemicals used in hydraulic fracturing and their changes through time, from the pre-

19

injected fracturing fluid to the produced water, was conducted. The characterization

20

consisted of a mass balance by dissolved organic carbon (DOC), volatile organic analysis

21

by gas chromatography/mass spectrometry, and nonvolatile organic analysis by liquid

22

chromatography/mass spectrometry. DOC decreased from 1500 mg/L in initial flowback

23

to 200 mg/L in the final produced water. Only ~11% of the injected DOC returned by the

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end of the study, with this 11% representing a maximum fraction returned since the

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formation itself contributes DOC. Furthermore, the majority of returning DOC was of the

26

hydrophilic fraction (60 - 85%). Volatile organic compound analysis revealed substantial

27

concentrations of individual BTEX compounds (0.1 – 11 mg/l) over the 405-day study.

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Nonvolatile organic compounds identified were polyethylene glycols (PEGs),

29

polypropylene glycols (PPG), linear alkyl-ethoxylates, and triisopropanolamine (TIPA).

30

The distribution of PEGs, PPGs, and TIPA, and their ubiquitous presence in our samples

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and the literature, illustrate their potential as organic tracers for treatment operations or in

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the event of an environmental spill.

33 34

1. Introduction

35

Unconventional oil and gas development and hydraulic fracturing has grown

36

steadily in recent years, with the advent of directional drilling and fracturing fluid

37

mixtures that permit economic recovery of shale resources. This is demonstrated by the

38

major U.S. shale basins (lower 48 states) accounting for 92% of the domestic oil

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production growth and all of the domestic natural gas production growth from 2011 to

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2014.1 The extraction of shale resources takes place by drilling both vertical and

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horizontal wells, followed by formation perforation, and the injection of fracturing fluids.

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Fracturing fluids are primarily water (~90%) and proppant (~9%), along with various

43

chemical additives (~1%) that enable operators to pump and deliver proppant through the

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borehole to elongate and prop-open fissures, creating surface area and continued access

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to oil and gas resources.2,3 Although the extraction of shale resources has had significant

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economic impacts, there are numerous environmental and public health concerns, 2



47

especially as it relates to water use and chemical additives associated with hydraulic

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fracturing.4–7

49 50

Water plays a key role in unconventional oil and gas development, from drilling

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to hydraulic fracturing. Hydraulic fracturing uses anywhere from 7,000,000 to

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50,000,000 L of water for a single well, depending on geological characteristics,

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horizontal length, operator, and type of fracturing method (i.e. slick water, gel, or hybrid-

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frac).8–10 The chemicals associated with hydraulic fracturing are also of environmental

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and public health interest, especially considering that 1% can amount to 500,000 L of

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chemicals used per well (vol:vol). The fracturing fluids are injected into the formation

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and return to the surface along with the hydrocarbons over the life of the well, generating

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a complex wastewater referred to as “flowback” in the initial stages of the well, and

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produced water during the oil and gas production phase (collectively referenced herein as

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“produced water”). Produced waters are a complex mixture of organic and inorganic

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constituents, that originate either from the fracturing fluid (>1,000 chemicals potentially

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used)

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radioactive material [NORM]),13 or as a result of subsurface reactions between the

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two.12,14 It has been estimated that over 3x1012 liters of produced water are generated

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annually in the U.S. alone, creating a substantial waste stream for the oil and gas

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industry.15

9,11,12

, the shale formation (i.e. hydrocarbons, salinity, metals, naturally occurring

67 68

There are environmental concerns related to produced waters and their ability to

69

reach the environment through well casing failures, surface spills, and inadequately

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treated produced water.16–18 These concerns also arise from the most common

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management practice, disposal of water through deep-well injection (95% of wells),

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which has recently been linked to seismic activity19 and the introduction of endocrine

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disrupting chemicals to the surrounding environment.20 The potential environmental

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impacts of produced water can be countered by their potential benefits, particularly for

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water stressed regions, if treated and managed properly (e.g. irrigation of crops).

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Therefore, the need to improve our understanding of produced water constituents,

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specifically their organic composition, for environmental release scenarios or reuse

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situations is vitally important.

79 80

Numerous publications have presented data on the inorganic constituents found in

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produced water samples,21–25 while a paucity of literature exists on the organic

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constituents.12,26,27 Review articles have identified and prioritized organic chemicals that

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have been reported in fracturing fluid mixtures9,11,28 and that could return in produced

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water.5,7,12 However, there are only a few studies to date that target organic chemicals in

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produced water samples, with several focused solely on non-polar compounds (i.e.

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hydrocarbons),14,29 and the few studies that do include the polar fraction have analyzed a

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limited number of samples.3,30,31 Furthermore, the majority of this research has been

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conducted on dry formations (e.g. gas producing), with little research as whole on wet

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formations (e.g. oil and gas producing).27

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The objectives of this study were, first, to characterize and perform a mass

92

balance of the organic constituents found in the fracturing fluid and the returned

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produced water over a one-year period from a single well using non-specific organic

94

analyses (DOC, hydrophobicity, and fluorescence). The second objective was to identify

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and to follow over time specific volatile and nonvolatile organic compounds. Thirdly, and

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finally, we assessed the possible environmental hazards and removal mechanisms of

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identified organic compounds during different stages of production. As such, this work

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presents a unique comprehensive long-term study of the presence of organic compounds

99

used and returned in a hydraulically fractured well.

100 101

2. Methods

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2.1. Well Characteristics and Water Samples

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The focus of our study was a well located in Weld County, CO, which produces

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both oil and gas from the Niobrara Formation at a depth of around 2,000 meters. The well

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was completed using a gel-based hydraulic fracturing fluid with around 11,000,000 L of

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water. The fracturing fluid included 10 different proprietary chemical mixtures for a total

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of around 87,000 liters/Kg of chemicals injected (SI Table 1; FracFocus and operator’s

108

well report). Water volume returned was from the separator’s water meter, which data

109

logs the flow of water over time.

110 111

The water samples collected from this individual well included the water used to

112

make the fracturing fluid (groundwater), the pre-injected fracturing fluid prior to

113

injection, and nine produced water samples over time. The first produced water sample

114

was taken during the first day (day 1) of the well flowing back, after a 30-day shut-in

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period. Samples were collected on days 4, 7, 15, 22, 80, 130, 220, and 405 after flowing

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back the well. The samples taken on days 1 and 4 were drawn from a tank connected

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directly to the well head (emptied every 4 to 6 hours), and all other produced water

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samples were taken directly from the onsite gas/oil/water separator. All samples, except

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for the fracturing fluid (wide mouth glass jar) were collected in pre-combusted (550°C

120

for 4 hr) 1-L amber bottles with no headspace. Samples were immediately transported

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back to the lab and stored at 4°C prior to analysis (< 5 days). Further details about the

122

well, sampling procedure, and fracturing fluid can be found in Rosenblum et al. (2017).32

123 124

2.2. Dissolved Organic Matter Characterization, Fractionation, and Mass Balance

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The characterization and fractionation of dissolved organic carbon (DOC) was

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conducted at the U.S. Geological Survey laboratory (Boulder, CO). The fractionation was

127

done using XAD resins, according to Aiken et al. (1992),33 and included HPI as the

128

hydrophilic fraction (not retained by XAD resins), TPIA as transphilic acids (retained by

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XAD-4), and HPOA as hydrophobic organic acids (retained on XAD-8). DOC analysis

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(non-purgeable organic carbon) of unfractionated water and XAD fractions was

131

conducted using a TOC-Vcph analyzer (Shimadzu Corp., Japan). In addition to these

132

analyses, ultraviolet light absorbance was measured using an Agilent 8453 photodiode

133

array UV-Vis spectrophotometer, with specific ultraviolet absorbance (SUVA254)

134

calculated (UV absorbance in cm-1 divided by TOC in mg/L), and a spectrofluorometer

135

(Horiba FluoroMax-3, NJ; Raman units [RU]) was used to generate an excitation-

136

emission matrix; all samples were filtered through a 0.45-µm prior to analysis.34

137

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The mass balance was performed, and normalized to the mg of carbon in the

139

fracturing fluid, using Equation 1, where V is volume (L) and C is DOC concentration

140

(mg/L). The index corresponds to the order the samples were taken (i.e., i=2, day 4;

141

i=3…i=10, day 405). Values used and calculated are presented in SI Table 2. : =

"

$

+

#

+

∑+ , " &, − , ) $

+ ) * "

142 143

2.3. Anion Determination

144

The Laboratory for Environmental and Geological Studies (LEGS) at the

145

University of Colorado Boulder performed the chloride analyses using ion

146

chromatography (Dionex Series 4500I). Samples were diluted by x 10, x 100, and x 1000,

147

with the average value being calculated from these three dilutions, if the levels were

148

above the analytical method detection limit.30

149 150

2.4. Volatile and Polar Organic Compound Analysis

151

Volatile organic compounds (VOCs) were determined from headspace-free 40-

152

mL volatile organic analysis (VOA) vials. VOCs were determined by purge and trap (OI

153

Analytical- 4660) gas chromatography mass spectrometry Agilent 6890 and 7890 GC-

154

MS) by a NELAC/A2LA accredited lab using EPA method 8260C (Origins Laboratory

155

Inc., Denver CO). Polar organic compounds were determined using ultrahigh pressure

156

liquid chromatography (1290 Agilent UHPLC; Agilent Technologies, CA) with an

157

ultrahigh definition quadrupole time-of-flight mass spectrometer (qTOF-HRMS; 6540

158

Agilent qTOF; Agilent Technologies, CA), with a 2-5% error of signal intensity for direct

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injection. All samples were filtered through a 0.2-µm filter (Acrodisc), and 10 µL were

160

injected onto a reverse phase C8 analytical column (Zorbax Eclipse XDB-C8). The

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mobile phases were H2O with 0.1% formic acid and acetonitrile. The chromatographic

162

method was: 5 minutes (10% H2O with 0.1% formic acid/90% acetonitrile), followed by

163

linear gradient to 100% acetonitrile after 30 minutes, with a flow rate of 0.6 mL/min. Ions

164

were generated using electrospray Jet Stream Technology, operating in positive ion

165

mode. The data were processed using MassHunter software (version 6.1). This method

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and details about the filters used during sample preparation are further described in

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Thurman et al. (2014)3. Triisopropanolamine (98%) was purchased from Acros Organics.

168 169

3. Results and Discussion

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3.1. Dissolved Organic Carbon (DOC) and Mass Balance

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The

non-specific

organic

characterization

(DOC,

hydrophobicity,

and

172

fluorescence) of the groundwater, fracturing fluid, and produced water samples are

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presented in this section. Figure 1A shows the concentrations of DOC and chloride from

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the beginning to the end of the study. DOC concentrations ranged from ~1500 mg/L in

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day 1 flowback water to ~200 mg/L in the final produced water (SI Table 3), which is

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approximately a ten-fold decrease in total DOC. The pre-injected fracturing fluid had a

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DOC of ~2200 mg/L, while the groundwater used to mix the fracturing fluid was ~5

178

mg/L DOC (SI Table 3); thus, the addition of fracturing fluid additives increased the

179

DOC by several orders of magnitude. SI Table 1 shows the list of ingredients and their

180

volumes from the FracFocus report and Well Report for this well, including 37,000 L of

181

guar slurry, 11,000 L of non-emulsifiers (proprietary surfactants), and additional organic

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ingredients that likely contributed to the measured DOC. Chloride concentrations rapidly

183

increased from day 1 to day 22, and then appeared to reach a pseudo steady-state over the

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remainder of the study (Figure 1A and SI Table 3).32 Figure 1B shows chloride versus

185

DOC concentrations over time.

186 187

B

2000

12000

1500

9000

ClDOC

1000

Cl- (mg/L)

DOC (mg/L)

A

e Tim

1 Day

0

0 0

188

6000 3000

500

400 Day

100

200

300

1500

400

1000

500

0

DOC (mg/L)

Time (Days)

189

Figure 1: Concentration of chloride and DOC in the produced water samples over time

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(A), and Cl- versus DOC over time (B). Note, the y-axis for chloride represents both plots

191 192

The observed decline in DOC concentrations with time is consistent with other

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studies that investigated DOC in wells over time.35–37 Hayes, who investigated several

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wells with 3 to 5 samples over 90 days, had similar findings regarding DOC over time for

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the majority of the wells studied,35 whereas Cluff et al. had nearly the same trend for the

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three wells they investigated.36 Kim et al., who investigated two Denver-Julesburg Basin

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(DJ-Basin) samples over 200 days, showed similar total organic carbon (TOC) results to

198

those seen here; although they had roughly a 50% decrease in TOC over the 200 days

199

compared to our 70% decrease of DOC over 220 days.37 Furthermore, research that has

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200

denoted the age of a produced water (time since flowback) have generally shown

201

declining levels of DOC, chemical oxygen demand (COD), or TOC over time.38–40

202 203

A mass balance was performed for the DOC measured in the produced water

204

samples to determine the percentage of DOC returning over the course of the study

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(Figure 2). Approximately 10.5% of the injected DOC returned by day 220, and only an

206

additional 0.6% returned between days 220 and 405 (11.1%). This 11.1% represents a

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maximum fraction returned, because the formation itself contributes DOC, which is not

208

discernable from the fracturing fluids DOC. Therefore, these results indicate that a small

209

percentage of DOC from the injected fracturing fluids returns to the surface over 405

210

days of operation (< 11.1%). This 11.1% does not consider the volatile organic

211

compounds (VOCs), because they are removed during non-purgeable organic carbon

212

analysis, so the TOC recovered is likely slightly higher than the 11.1% of the DOC

213

observed. This low level of returning DOC is not seen with the returning water volumes,

214

which had around 34% of the volume injected return by day 405 (Figure 2); more than

215

three times that of the DOC.

216 217

These DOC results could be solely from dilution and mixing with subsurface

218

brine, however it is likely the returning fluid is influenced by more than just dilution and

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mixing, which is often thought to be a key contributor to the total dissolved solids (TDS)

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of returning produced waters.32 A combination of effects, such as sorption,

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biodegradation, subsurface reactions, or imbibition are likely playing a role. Sorption is

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likely due to the organic-rich mud, shale, and hydrocarbons present within the borehole

10



223

that could sequester DOC from the produced water. Biodegradation is also possible since

224

there were high levels of DOC that could be labile (i.e. guar).41 A significant diversity of

225

microorganisms have been shown to return in produced water,36,42 even in the presence of

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biocides.43 Imbibition in particular is important to consider, even for oil and gas bearing

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formations,44 since it has been proposed that the majority of injected fluids are retained

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(e.g. imbibed) in shale formations and that the returning waters are primarily natural

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occurring formation brine.45 Thus, the 34% of injected water that returned (Table SI 2;

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4% increase from Day 220 to Day 405), which again represents a maximum fraction

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returned because much of the returning volume is likely influenced by the formation

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itself, suggests that a substantial volume injected was likely imbibed in the formation.

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Furthermore, Kim et al (2016)37 performed a mass balance of returning DJ-Basin

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produced water over time, and saw significant variation in their frac fluid additive

235

recoveries, with recoveries of aluminum at 3%, zirconium at 9%, and potassium at

236

33%.37 Therefore, the data and literature suggest that imbibition, along with

237

mixing/dilution, could both be playing significant roles, while sorption and

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biodegradation could also be contributing, and that it is additive-specific. Furthermore,

239

this 11.1% returned DOC could be composed of injected, formation, and subsurface

240

reaction based DOC, which make up the ~2,300 kg of DOC returned by day 405,

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including chemicals of environmental concern from either the fracturing fluid (i.e.

242

biocides) or formation (i.e. benzene), validating the need to characterize and identify this

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DOC.

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% DOC and Water Returned

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100

DOC

80

Water

60 40 20 0 0

244

100

200

300

400

Time (Days)

245

Figure 2: Percent of DOC returned based on a mass balance of ~24,000 Kg of DOC

246

injected. Percent of water returned is also plotted and was calculated using the volume

247

returned on that day relative to the volume injected (11,000,000 L).

248 249

3.1.1. Dissolved Organic Carbon Fractionation and Characterization

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The fractionation of produced waters DOC using XAD resins is a valuable

251

method for determining the distribution of organic matter class in oil and gas

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wastewater.30 The fractionation results for the produced waters over time indicate the

253

majority of DOC for all of the samples and fracturing fluid was composed of low

254

molecular weight hydrophilic compounds (HPI; Figure 3a). This is in agreement with

255

Lester et al. (2015)30 who investigated a single DJ-Basin flowback sample.30

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The day 1 sample had the highest percentage of hydrophilic acid (HPI; Figure

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3A). The percentage of HPI steadily decreased over time, similar to that of the DOC

258

(Figure 3A & B). HPI has been linked to simple organic acids (e.g. acetic acid), which

259

can be found at high levels in produced waters.30 HPI and hydrophilic neutral compounds

260

are also likely responsible for much of the polar organic constituents (i.e. guar), and they

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have been reported to consist of proteins and carbohydrates.46,47 Carbohydrates are of

262

particular interest, since they are generally used as gelling agents (i.e., guar) during

12



263

hydraulic fracturing and were used in the well, studied herein (SI Table 1). This result,

264

then suggests that the gelling agents, which would be found in the HPI fraction, could be

265

responsible for a significant portion of the DOC in these samples. This hypothesis is

266

supported by the concentration of guar slurry injected (SI Table 1) and the trends shown

267

in Figures 1 and 3B, which illustrate that DOC and HPI follow nearly identical trends

268

over time. However, it should be noted that the HPI could also consist of acetone, acetic

269

acid, and other hydrophilic DOC compounds that are known to be present in produced

270

waters, either from the formation or the injected fluid.29,30

271 272

The other fractions, transphilic acids (TPIA) and hydrophobic organic acids

273

(HPOA), increase relative to the total measured DOC over time (Figure 1 and Figure 3A).

274

TPIA is thought to consist of intermediately polar compounds and has been linked to

275

aromatic constituents with acidic functional groups, which have been found in produced

276

water.14,48 HPOA is generally thought to consist of the less polar compounds and has

277

been associated with humic material, along with phenols and cresols,49 which have been

278

measured in DJ-Basin produced waters.30 Since these fractions increase relative to the

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total DOC over time (Figure 3A), it is likely that these fractions are mostly from the

280

formation water and not the injected fluid. However, it is important to note that these

281

fractions could also be forming in the subsurface from the degradation of injected

282

compounds. This is illustrated in Figure 3B, which shows TPIA and HPOA

283

concentrations decrease by 43% and 48%, respectively, while the HPI fraction decreased

284

by 89%.

285

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B HPI TPIA

80

HPOA

60 40 20

80

1000

60 40

500

20 0

0 100

200

300

400

Time (Days)

Time (Days)

286

1500

HPI TPIA HPOA

0

80 13 0 22 0 40 5

22

7

15

4

1

0

100

HPI DOC mg/L

Percent of Total DOC

100

TPIA or HPOA DOC (mg/L)

A

287

Figure 3: DOC fractionation of produced waters over time by XAD resins 4 and 8 (HPI,

288

hydrophilic fraction; TPIA, transphilic acids; HPOA, hydrophobic organic acids).

289 290

UV absorbance at 254nm (SUVA254) and fluorescence were measured on all of

291

the samples.50 Results are presented in SI Table 3 and SI Figure 1. The results for UV

292

absorbance at 254nm show decreasing absorbance over time, while SUVA254 increases

293

slightly over the course of the study. As UV absorbance at 254nm is generally linked to

294

aromaticity, it is likely that SUVA254-rich formation-based aromatic constituents (e.g.,

295

benzene) not solely linked to the original fracturing fluid constituents were introduced.

296

That is, the UV 254nm values do not decrease proportionally to the DOC over time

297

(SUVA254), suggesting that a portion of the DOC that absorbs highly at 254nm could be

298

from the formation. Excitation emission matrices were generated from the fluorescence

299

data (SI Figure 1). The discussion of these results is presented in the SI, along with SI

300

Figure 1.

301 302

3.2. Characterization and environmental implications of Volatile Compounds

14



303

The determination of specific volatile compounds and their environmental

304

implications are presented in this section. Sixty-five volatile organic compounds (VOCs)

305

were determined in all of the samples from the pre-injected fracturing fluid to produced

306

water recovered on day 405. Selected results are presented in Figure 4, which shows

307

VOC concentrations over time (concentrations of VOCs and their reporting limits are

308

presented in SI Table 4). The groundwater, which was stored on site, contained three

309

VOCs: 2-hexanone (312 µg/L), acetone (44.7 µg/L), and benzene (8.08 µg/L). Their

310

presence could be the result of chemicals (i.e. biocides, preservatives) added to the

311

storage container, produced water previously stored in the tank, the groundwater, or from

312

these volatile chemicals being transported (i.e., air) to the open storage tank during

313

drilling operations.

314 315

The pre-injected fracturing fluid contained several VOCs including 2-butanone

316

(10.7 mg/L), acetone (230 mg/L), bromomethane (0.07 mg/L), and chloromethane (0.03

317

mg/L). Acetone has been detected in flowback and produced water, as well as ambient air

318

around oil and gas wells, and is thought to be a common solvent used in cleaning

319

purposes.30,35,51 2-butanone has also been previously reported in produced water, and is

320

thought to be used as a friction reducer or industrial solvent.35 Chloromethane has been

321

described as a fracturing fluid additive, but has yet to be detected in produced water.9,52

322

Neither chloro- or bromomethane were detected in any produced water samples,

323

suggesting that they either transform downhole or sorb to the formation and particles in

324

the borehole.14

325

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3.2.1. BTEX and Substituted Benzenes

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Benzene, toluene, ethylbenzene, and xylene (BTEX) were found in the mg/L

328

range in every produced water sample analyzed (Figure 4A), and are frequently detected

329

in produced waters and oil and gas impacted waters.14,29,30,35 Ethylbenzene and xylene

330

concentrations appear to decrease overtime, after day 22, while toluene decreases until

331

day 220 then increases on day 405. Benzene concentrations varied over the course of the

332

study with no particular trend. Benzene concentrations ranged from 6-12 mg/L, with the

333

lowest concentration being detected on day 220, while the second highest concentration

334

was detected on day 405 (Figure 4A). The high concentrations of ethylbenzene and

335

xylene in the early samples that peaked at day 22, suggest that BTEX compounds could

336

have been constituents of fracturing fluid additives (e.g. components of petroleum

337

distillates), even though they were not detected in the pre-injected fracturing fluid

338

sample. Nonetheless, the high concentrations observed for BTEX over the course of the

339

study suggest that substantial amounts are introduced from the formation, probably from

340

the oil in this formation, which would be anticipated for water in contact with an oil-

341

bearing shale. These concentrations are an order of magnitude lower than that recently

342

found in the Permian Basin produced waters (average concentration = 107 mg/L, n=8)29,

343

whereas other oil-bearing formations have shown high variations in reported benzene

344

levels from 0.026 to 4 mg/L.53–56

345 346

Benzene concentrations measured for all of the produced waters in the time series

347

studied are of environmental concern in the event of a spill/release, or if the produced

348

waters are to be used for applications other than recycling for future hydraulic

16



349

fracturing.29,57,58 These environmental concerns are the result of benzene concentrations

350

being orders of magnitude higher than both the maximum contaminant level (MCL;

351

0.005 mg/L) and discharge permit levels used in produced water treatment facilities

352

(Pennsylvania [PA], U.S.).17 Toluene was also present in concentrations greater than its

353

MCL (1.0 mg/L) and PA discharge permits for all of the produced waters in the time

354

series studied.17 Ethylbenzene was greater than its MCL (0.7 mg/L) for days 7, 22, and

355

80, while xylenes were never greater than its MCL (10 mg/L total xylenes).

356

17


Page 18 of 41

Page 19 of 41


Xylenes, total Toluene Ethylbenzene Benzene

A 15

mg/L

10

5

0 0

100

200

300

400

Time (Days)

B 1,2,4-Trimethylbenzene 1,3,5-Trimethylbenzene Isopropylbenzene sec-Butylbenzene

2.5

mg/L

2.0 1.5 1.0 0.5 0.0 0

100

200

300

400

Time (Days)

C 2.5

2-Hexanone 2-Butanone 4-Methyl-2-pentanone

mg/L

2.0 1.5 1.0 0.5 0.0 0

100

200

300

400

Time (Days)

357 358

Figure 4: Concentrations of BTEX (A), select methylbenzenes (B), and select ketones (C)

359

in produced water samples over time (day 1 to day 405).

360 361

Substituted benzenes were found at or near mg/L concentrations during the early

362

stages of the well (day 1 to day 80), and were above the limit of detection until day 220 18



363

(Figure 4B). These four substituted benzenes all have the same trend, with concentrations

364

increasing until day 22 and then decreasing until day 200 and being below the detection

365

limit by day 405, suggesting they are likely associated with fracturing fluid additives.

366

1,2,4-trimethylbenzene, 1,3,5-trimethylbenzene, and isopropylbenzene have been

367

described as fracturing fluid additives, and have also been detected at the µg/L range in

368

produced water from both the Barnett and Marcellus shale.9,35,59 1,2,4-trimethylbenzene

369

has been described as a surfactant, corrosion inhibitor, and friction reducer and has also

370

been reported in surface water near treatment facilities that receive oil and gas fluids in

371

Pennsylvania.17 Both 1,2,4-trimethylbenzene and 1,3,5-trimethylbenzene were also

372

recently reported in monitoring wells near a hydraulically fractured well in Wyoming.60

373

Substituted benzenes have been shown to be irritants (i.e. eye, skin, and respiratory)61,

374

although no MCLs or oral reference doses exist for these four compounds; however a

375

recent study did quantify their potential toxicity using a quantitative structure-activity

376

relationship model.62 Therefore, the environmental impacts associated with substituted

377

benzenes are not well understood and require further research.

378 379

3.2.2. Ketones

380

Numerous ketones were at the mg/L level for portions of the study. Acetone was

381

the ketone detected at the highest concentration on day one (22 mg/L) and was detected

382

over the course of the study with concentrations ranging from 0.6 mg/L on day 7 to 9

383

mg/L on day 405. The levels of acetone over the course of the study are likely due to its

384

high concentration in the fracturing fluid (230 mg/L), meaning it would take a substantial

385

amount of time to dilute (i.e., formation water), sorb, or biodegrade acetone from the

19


Page 20 of 41

Page 21 of 41


386

returning produced water. Also the polar nature of acetone would support its presence in

387

the water fraction for an extended period of time, whereas non-polar or mid-polar

388

compounds would partition into the oil. Acetone has been detected in numerous produced

389

waters, been found to form during biodegradation of fracturing fluid additives, and has

390

been reported as a fracturing fluid additive.9,30,35,41,52 Acetone has been described as “less

391

toxic” than other industrial solvents,61 and although it does not have an MCL, it has an

392

oral reference dose (RfD) of 0.9 mg/kg/day, which is more than three times that of the

393

total xylenes RfD (0.2 mg/kg/day). Total xylenes has an MCL of 10 mg/L.

394 395

The other ketones detected were 2-hexanone, 2-butanone, and 4-methyl-2-

396

pentanone (Figure 4C). 2-Hexanone was detected at its highest concentration on day 1 (1

397

mg/L) and was last detected on day 130 (0.1 mg/L), suggesting that it could have been

398

formed in the subsurface or from an unknown source. 2-hexanone has not previously

399

been reported in produced water or as a chemical additive used in hydraulic fracturing,

400

thus supporting the notion that it was formed during a subsurface reaction, potentially due

401

to the use of tert-butyl peroxide, which is a strong oxidant. 2-hexanone was historically

402

used in paint, paint thinner, and various chemical processes.63 However, because 2-

403

hexanone was determined to have negative health effects as a neurotoxin, it now has

404

restricted uses in the U.S.63 It has an RfD of 0.005 mg/kg/day, which is the same RfD

405

value as benzene and dichloromethane.64 Thus, 2-hexanone is a chemical of concern

406

because it was found in the produced water samples for at least 130 days.

407

20



Page 22 of 41

408

2-butanone was detected at 10 mg/L in the fracturing fluid, but was not detected

409

until day 80 in the produced waters samples. This is different than acetone, which was

410

detected at high levels in the fracturing fluid and was also detected in the day 1 sample.

411

These unexpected results for 2-butanone could reflect subsurface reactions. That is, 2-

412

butanone could be yielding 2-hexanone in the early stages of the well, because 2-

413

butanone was detected in the fracturing fluid and appears to increase over time while 2-

414

hexanone is decreasing (Figure 3c). However, the addition of an ethyl group to 2-

415

butanone seems unlikely, even in the presence of a strong oxidant (i.e. tert-butyl

416

peroxide). Nonetheless, 2-butanone appears to be a fracturing fluid additive, even with

417

its unanticipated levels over the course of the study because it was detected in the

418

fracturing fluid, reported as a fracturing fluid additive,9 and has also been detected in

419

produced water and waters impacted by produced water.30,60

420

pentanone was at or near mg/L levels from day 1 until day 22, but was not detected by

421

day 80. This suggests that it was likely associated with the fracturing fluid and not the

422

formation. 4-methyl-2-pentanone has been described as a fracturing fluid agent, and is a

423

common solvent used in industrial processes.9 2-butanone (RfD of 0.6 mg/kg/day) and 4-

424

methyl-2-pentanone (reference concentration for inhalation exposure of 3 mg/m3) have

425

been shown to effect developmental and musculoskeletal systems.64 This could support

426

monitoring for both chemicals in the event of a spill, particularly 4-methyl-2-pentanone

427

in the early stages (i.e. first few weeks) of the well and 2-butanone at the later stages (i.e.,

428

first year).

429 430

3.3. Semi-Polar and Non-Polar Organic Compounds

21


Finally, 4-methyl-2-

Page 23 of 41


431

The analysis for specific polar organic compounds and their environmental

432

implications are presented in this section. The UHPLC-Q-TOF-HRMS total ion

433

chromatograms (TIC) for the pre-injected fracturing fluid and five produced water

434

samples are shown in Figure 5. The peaks visible in the TIC are dominated by three

435

classes of homologues, which have been previously identified in produced waters (Figure

436

5): polyethylene glycols (PEGs)3, polypropylene glycols (PPGs)65, and linear alkyl

437

ethoxylates (LAEs).3 These three homologous compounds were identified in the

438

fracturing fluid and the produced water samples, and generally decreased in magnitude as

439

the produced waters age increased (Figure 5). During hydraulic fracturing, surfactants are

440

added to aide in the pumping of fracturing fluids and the movement of sand and oily

441

substances.30 The surfactants are thought to be potential fingerprinting compounds, since

442

they are identified so frequently in produced waters and waters impacted by them.3,17,65,66

443

Their substantial signal in both the fracturing fluid and produced waters, along with their

444

presence over the course of the study supports this notion, specifically for PEGs and

445

PPGs. It should also be noted that PEGs were detected in the groundwater samples from

446

3.5 to 11.5 min (SI Figure 2), and could have been the result of biocide addition in the

447

tank, since they were added to prevent microbial growth during storage; although they

448

could have also been from flowback and produced water that were mixed or previously

449

stored in the holding tank.

450

22



451 452

Figure 5: Total ion chromatogram (TIC) of five produced water samples over 220 days

453

and the pre-injected fracturing fluid (insert above other TICs). Note the inserted

454

fracturing fluid TIC is compressed to fit the figure and is not to scale on the y-axis

455

(relative abundance). Polyethylene glycols (PEGs), polypropylene glycols (PPGs), and

456

linear alkyl ethoxylates (LAEs) are denoted in the figure, along with triisopropanolamine

457

(TIPA). The x- and y-axes represents the acquisition time and the relative size of the

458

peaks (counts), respectively. Samples were analyzed as received (< 48 hours of

459

sampling). It is important to note, that there are numerous other compounds present in

460

these samples and in the regions identified (as PEGs, PPGs, LAEs, and TIPA), and that

461

these identifications are shown to illustrate the major ions present and not the total

462

compounds present.

463 464

The PEGs were detected from 4.4 min to 14.0 min (more hydrophilic zone). The

465

PEGs showed increasing ethylene oxide (EO) units, from PEG-EO4 to PEG-EO16 with

23


Page 24 of 41

Page 25 of 41


466

accurate masses of 217.1050 m/z (Na+ adduct; retention time 4.4 min; 2.0 ppm error) and

467

740.4645 m/z (NH4+ adduct; retention time 12.4 min; 1.0 ppm error), respectively

468

(sample, day 1). The average mass difference between PEGs was 44.0262 mass units,

469

representing the addition of one ethylene oxide group [-CH2-CH2-O-]. The next class of

470

compounds was PPGs, which were detected from 14.6 min to 22.2 min and show

471

increasing propylene oxide units from PPG-PO4 to PPG-PO12 with accurate masses of

472

273.1673 m/z (Na+ adduct; retention time 14.6 min; 0.2 ppm error) and 732.5470 m/z

473

(NH4+ adduct; retention time 22.2 min; 0.5 ppm error), respectively (sample, day 1). The

474

PPGs had an average mass difference of 58.0419 mass units that is equal to a propylene

475

oxide group [-CH2CH(CH3)-O-].

476 477

The LAEs were detected from 22 min to 26.8 min and show four different classes

478

of LAEs that have varying carbon chain lengths (C9, C10, C11, and C12). This work

479

describes the first putative identification of LAEs in produced water with carbon chain

480

lengths of 9, 10, and 11 (SI Table 5), whereas the 12 carbon chain length LAEs have

481

previously been described.3 The LAEs had an average mass difference of 44.0262 mass

482

units that is equal to an ethylene oxide group [-CH2-CH2-O-]. The LAEs included over 25

483

unique putatively identified compounds, from LAE9-EO13 to LAE12-EO9, which had

484

accurate masses of 734.5266 m/z (NH4 adduct; retention time 22 min; 0.8 ppm error) and

485

600.4688 m/z (NH4 adduct; retention time 26.8; 1.2 ppm error), respectively (samples,

486

day 1 and day 15). It should be noted that individual standards are not available for PEGs,

487

PPGs, and LAEs, with only homologue mixtures available at this time, with these

488

compounds being identified and semi-quantitated.

24



489 490

PEGs, PPGs, and LAEs are common products in personal care products,

491

medicines, foods, and industrial processes.65 For instance, PEGs are used in laxatives,

492

PPGs are used in ice cream, and LAEs are often found in detergents.65 Their use in

493

commercial products that humans frequently ingest or are in contact with suggests they

494

are not acutely toxic; however, the extent of polymerization is crucial when considering

495

toxicity.65 PEGs of high molecular weight have been described as inert and non-toxic,67

496

while the monomer ethylene glycol has known human toxicity.68 PPGs have been shown

497

to have a similar relationship to that of PEGs, with polymers or high molecular weight

498

PPGs being considered safe,69 while the monomer propylene glycol is considered toxic.70

499

Similarly, LAEs are considered harmless as a polymer.71,72 However, the monomer

500

ethylene glycol can be formed, because the LAEs studied here can have up to 13

501

repeating ethylene oxide groups that are attached to a carbon chain (SI Table 5).68

502

Therefore, consideration of whether the monomer is being formed is a key research

503

question, especially considering the use of strong oxidants as breakers, high temperatures

504

and pressures in the well, and biological processes in the subsurface that could lead to

505

monomer formation. It should be noted that the monomers discussed here are not

506

detectable in our UHPLC-Q-TOF-HRMS, and should be investigated in future research

507

of produced waters.

508 509

The compound triisopropanolamine (TIPA) was found in every sample from the

510

fracturing fluid to day 405. The peak can be seen in Figure 5 around 2.8 min. TIPA was

511

identified by its accurate mass of 192.1594 m/z, corresponding to the protonated molecule

25


Page 26 of 41

Page 27 of 41


512

and elemental formula C9H21NO3. TIPA was further confirmed by retention time,

513

accurate mass, and by performing MS-MS on a pure standard that validated the putative

514

identification, with major fragments at 174.1494 m/z and 156.1383 m/z, (SI Figure 3).

515

The resulting concentration appears to be in the mg/L range for all of the samples

516

analyzed, with relative intensities comparable to the 1 mg/L standard.

517 518

TIPA is a tertiary amine, which is typically used as an emulsifier, stabilizer, and

519

surfactant during industrial processes. It is also frequently used in cements as a hardening

520

accelerator.73 TIPA has been reported as a fracturing fluid additive11,52 but had yet to be

521

reported in a produced water sample. TIPA is an industrial agent that has been described

522

as a moderate irritant for skin and a severe irritant for eyes,61 but has been shown to be

523

non-toxic or genotoxic in in-vitro bioassays.74

524 525

3.3.2. Surfactant Levels Over Time

526

Figure 5 and 6 illustrate the substantial changes in concentration of PEGs, PPGs,

527

LAEs, and TIPA in the produced water samples over time. All three surfactants

528

decreased in line with their hydrophobic nature (octanol-water partition coefficient; Kow),

529

i.e., the most hydrophobic LAEs decreased most rapidly followed by the PPGs, and then

530

PEGs.75 Because a quantitative measure would be challenging due to matrix-induced

531

ionization effects and specific response factors for these types of compounds,17 relative

532

abundance was used as a way to compare these compounds levels over time (i.e., semi-

533

quantitative).

534

26



535 536

Figure 6: Relative abundance (concentration at time, t / original concentration; Ct/Co) of

537

the highest detected surfactants from each class (PPG-PO6, PEG-EO6, and LAE11-EO9),

538

and TIPA over the course of the study from the day 1 sample to day 405.

539 540

Hydrophobicity, as expected, is a key indicator for what injected chemicals are

541

present in the produced waters over time. This is demonstrated by the identified

542

compounds’ Kow values and their elution time through the UHPLC, because the least

543

hydrophobic compounds elute from the column first, while the most hydrophobic

544

compounds elute last. The PEGs are the least hydrophobic surfactants with an estimated

545

log Kow of -2.35 earliest elution time and the greatest relative abundance (Figure 5) over

546

the course of the study. The PPGs had the second highest concentrations among the

547

samples analyzed, have an estimated log Kow of -0.25, and eluted after the PEGs. In

548

contrast, LAEs, for which the concentrations decreased the fastest, have an estimated log

27


Page 28 of 41

Page 29 of 41


549

Kow of 2.4,5 the highest of the surfactants studied, and also eluted the latest. These results

550

suggest the LAEs are likely partitioning into the oil phase or sorbing to the formation or

551

particles in the wellbore (LAE estimated log Koc= 1.45 [carbon-normalized sorption

552

coefficient]), which could explain the rapid removal from the water phase of the LAEs

553

compared to PPGs and PEGs. Conversely, the PEGs and PPGs, both with lower Kow

554

values, indicating that they will remain in the aqueous phase rather than partitioning into

555

the shale or oil phase, were detected in the produced water throughout the study period

556

(Figure 5). This hypothesis is further supported by TIPA, which remained at the highest

557

concentrations over time and had an estimated log Kow of -1.25 (Figure 5). Although its

558

estimated Kow is slightly higher than the PEGs, TIPA’s hydrophilic nature is illustrated

559

by its early elution time in the TIC (2.8 min) compared to PEG-EO6 (9.5 min) or PEG-

560

EO4 (4.4 min), which further supports the role hydrophobicity plays on returning

561

chemicals.

562 563

These results show how surfactants change over time, in terms of what class of

564

compounds might be present and how their concentrations change. The results also

565

support the importance of a chemical’s hydrophobic nature, and how that dictates when

566

the chemical will return in an oil-bearing formation. This is important when considering

567

the chemicals to target as tracers in the event of a spill or water reuse scenario,

568

particularly for an oil and gas containing formation. That is, the water and oil are

569

constantly mixing in the borehole until they reach the separator, providing substantial

570

time for compounds to partition from the water to the oil. These findings coupled with the

571

presence of PPGs, PEGs, and TIPA over the course of the study, illustrate three indicator

28



572

chemicals that are unique to the water phase and that were found in the fracturing fluid

573

used (Figure 5). TIPA in particular could be of importance, due to its hydrophilicity, that

574

would result in TIPA being in produced waters for extended periods of time, along with

575

TIPAs non-ubiquitous nature compared to many surfactants (i.e. PEGs).

576 577

Overall, this study provides a unique organic characterization that fills a

578

substantial knowledge gap; that much of the injected DOC remains in the subsurface (on

579

a mass balance basis), and that the returning DOC is primarily hydrophilic based on the

580

return of the hydrophilic compounds, either volatile or non-volatile, over the 405-day

581

study period. Furthermore, this work newly-identified persistent compounds that remain

582

for long periods of time, and that have been found in produced waters around North

583

America or effluent discharges from a produced-water treatment facility.3,17,30,65,66 Future

584

research should continue to characterize the organic composition of produced waters (e.g.

585

in general and over time), with particular attention on hydrophilic organic compounds

586

and the suspended solids fraction, while work is also needed to characterize chemical or

587

biological degradation products of these specific constituents, and expound on the

588

physical mechanisms that impact the returning compounds.

589 590

Supplemental Information

591

Supplemental information includes tables and figures for the wells FracFocus report,

592

mass balance values, DOC and non-specific characterization, VOCs analyzed and

593

detected, Kendrick masses for LAEs, excitation-emission matrixes, the total ion

594

chromatogram of the groundwater used to make the fracturing fluid, and MS-MS spectra

29


Page 30 of 41

Page 31 of 41


595

for Triisopropanolamine. An Excel file includes all data generated by the USGS

596

presented in SI Table 3 and Figure 3. At the time of publication, data other than

597

presented in this paper are not publically available from the University of Colorado.

598 599

Acknowledgements

600

This work was supported by the AirWaterGas Sustainability Research Network, and was

601

funded by the National Science Foundation under Grant No. CBET-1240584. Opinions,

602

findings, recommendations, and conclusions conveyed in this paper are those of the

603

author(s) and do not necessarily reflect the views of the National Science Foundation.

604

Any use of trade, firm, or product names is for descriptive purposes only and does not

605

imply endorsement by the U.S. Government. The researchers would also like to

606

acknowledge Dr. Jessica Rodgers for her review of the manuscript, Dr. Avner Vengosh

607

for his insight on our data set, and our industry collaborators that permitted access and

608

took the time to help us collect the samples. The authors dedicate this paper to the

609

memory of George Aiken, colleague, mentor, and friend.

610 611 612 613

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