# Geochemical and isotopic evolution of water produced from Middle Devonian Marcellus shale gas wells, Appalachian basin, Pennsylvania
Elisabeth L. Rowan, Mark A. Engle, Thomas F. Kraemer, Karl T. Schroeder, Richard W. Hammack, and Michael W. Doughten

ABSTRACT 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 waterand solutes produced over the long term (>12 months). The question of whether the produced water originated within theMarcellus Shale, or whether it may have been drawn from adjacent reservoirs via fractures is addressed using measurements of
228 

### Ra ∕ 226 

### Ra and 226 

### Ra 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 δ 18 

### O values were observed in theproduced water, followed by more gradual changes until a compositional plateau was reached within approximately 1 yr. The δ 18 

### O 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

Published by The American Association of Petroleum Geologists. © 2015 U.S. Geological Survey. All rights reserved. Manuscript received August 11, 2013; provisional acceptance September 26, 2013; revised manuscript received March 26, 2014; revised manuscript pro visional acceptance May 13, 2014; 2nd revised manuscript received June 17, 2014; final acceptance July 07, 2014. DOI: 10.1306/07071413146 AUTHORS
Elisabeth L. Rowan ∼ U.S. Geological Survey, 12201 Sunrise Valley Drive, MS 956, Reston, Virginia 20192; erowan@usgs.gov
Elisabeth L. Rowan received an M.S. in geology from the University of California, Berkeley, and a Ph.D. in hydrogeology from the Pierre & Marie Curie University (University of Paris VI). Her current research in the USGS Energy Resources Program is on the geochemistry of water produced from oil and gas reservoirs in the Appalachian basin.

Mark A. Engle ∼ U.S. Geological Survey, University of Texas at El Paso, Dept. of Geological Sciences, 500 W. University Ave., El Paso, Texas 79968; engle@usgs.gov Mark A. Engle is a research geologist with the U.S. Geological Survey and serves as chief of the produced-waters project for the USGS Energy Resources Program. He holds a Ph.D. in hydrogeology from the University of Nevada, Reno. His research interests include aqueous geochemistry and geochemometrics.

Thomas F. Kraemer ∼ U.S. Geological Survey, 384 Woods Hole Rd, Woods Hole, Massachusetts 02543; tkraemer@usgs.gov
Thomas F. Kraemer holds a Ph.D. in marine geology and geochemistry from the University of Miami, Rosenstiel School of Marine and Atmospheric Sciences. He is an emeritus scientist at the U.S. Geological Survey, and the primary focus of his research is the geochemistry and radiochemistry of surface waters and deep sedimentary basin fluids.

Karl T. Schroeder ∼ U.S. Department of Energy, National Energy Technology Laboratory, 626 Cochrans Mill Road, MS 84-108, Pittsburgh, Pennsylvania 15236; Karl.Schroeder@netl.doe.gov
Karl T. Schroeder is a research chemist and currently serves as the director of the Engineered Natural Systems Division, U.S. Department of Energy. He holds a Ph.D. in organic chemistry from Duquesne University, and his research interests include the chemistries of fossil energy resources and byproducts.

AAPG Bulletin, v. 99, no. 2 (February 2015), pp. 181

– 206 181

### evaporatively concentrated pal eoseawater. The rapid transition from injected water to chemically and isotopically distinct water while <50 % of the injected water volume had been recovered, supports the hypothesis that significant volumes of injected water were removed from circulation by imbibition.

INTRODUCTION

The Middle Devonian Marcell us Shale extends from West Virginia to New York in the Appalachian basin (Figure 1), and is one of the largest shale gas resources in the United States. Estimates of recoverable natural gas in the Marcellus Shale range widely, but Coleman et al. (2011) provide a conservative estimate of 84 trillion cubic feet (tcf), or approximately 32% of the US totalnatural gas reserves (272.5 tcf) and approximately 10% of the estimated technically recoverable g as resources (862 tcf) (Kharaka et al., 2013). With increasing gas production from shale in the Appalachian basin, and across the US, greater attention is being paid to the water co-produced with the gas, or produced water (e.g., Blauch et al., 2009; Soeder, 2010; Chapman et al., 2012;Warner et al., 2012). Conventional vertical wells in the basin produce more water per unit of gas, but the large and growing number of horizontal shale gas wells makes them overall a greater source of produced water (Lutz et al., 2013). In the Appalachian basin, produced waters are typically Na-Ca-Cl brines with total dissolved solids (TDS) values from 100,000 to 300,000 mg/L (e.g., Poth, 1962; Dresel and Rose,2010), and therefore represent a challenge for reuse, treatment, or environmentally sound disposal. Although the waters co-produced with conventional gas and oil from Pennsylvanian

– Cambrian reservoirs in the Appalachian basin have been well studied, comparatively few studies have been published on the water produced with unconventional gas from the Middle Devonian Marcellus Shale (Figure 2). This investigation differs from previous studies by using geochemical and isotopic analyse s of time-series samples (i.e., collected from the same well at intervals for an extended period of time) to constrain the timing of the produced water ’ s transition from relatively dilute injected water used for hydraulic fracturing to a highly saline fluid (Figure 3A

– D). In Greene County, southwest Pennsylvania (PA), time-series samples of produced water were collected from three horizontal Marcellus Shale wells, and grab samples (i.e., a single sample collected at one specific time) from one vertical Marcellus Shale well. In Tioga and Lycoming Counties in north central PA, grab samples were collected from 12 horizontal wells in the Marcellus Shale and one in the Burket Richard W. Hammack ∼ U.S. Department of Energy, National Energy Technology Laboratory, 626 Cochrans Mill Road, MS 84-108, Pittsburgh, Pennsylvania 15236; richard.hammack@netl.doe.gov
Richard W. Hammack received an M.S. in geology (geochemistry) from West Virginia University in 1979 and joined the U.S. Bureau of Mines where he developed methods to treat acidic, metal-rich waste waters from mining and mineral processing. Since joining the U.S. Department of Energy in 1996, he has explored methods to treat, dispose, and beneficially use produced water from oil and gas operations.

Michael W. Doughten ∼ U.S. Geological Survey, 12201 Sunrise Valley Drive, MS 432, Reston, Virginia 20192; doughten@usgs.gov Michael W. Doughten received a B.S. in chemistry from George Mason University in 1980 and joined the U.S. Geological Survey the same year. He is the lab manager of the National Research Program ’ s Eastern Branch Analytical Chemistry Labs.

ACKNOWLEDGEMENTS We thank the staff of the operating companies for generously granting access to their wells for sample collection. We also thank the Department of Energy for facilitating collaboration through an ongoing research program, and for assisting with sample collection and analyses. We are grateful to Yousif Kharaka, Jennifer McIntosh, and an anonymous reviewer whose comments significantly improved the manuscript. Funding for this study was provided by the Energy Resources and Toxic Substances Hydrology Programs of the U.S. Geological Survey. Any use of trade, firm, or product names is for descriptive purposes only and does not imply endorsement by the U.S. Government.

EDITOR ’ S NOTE Color versions of Figures 1 and 3

– 9 can be seen in the online version of this paper.

182 Geochemistry of Produced Water from Marcellus Shale Water, PA

### Member of the Harrell Formation (Upper Devonian; Figures 1, 2). The origin of the saline water produced from the Marcellus Shale over the long-term (> ∼ 1 yr) is not universally agreed upon. One school of thought isthat the produced water consists of the low to moderate salinity water (commonly ∼ 50,000 mg/L TDS) injected during hydraulic fracturing, and returned to the surface with much higher salinity after dissolvinghalite, and other minerals present in lenses or dispersed crystals in the shale (Blauch et al., 2009).Another hypothesis is that the injected water mobilizes ions adsorbed onto clay minerals, then returns to the surface with markedly higher salinity (Striolo et al., 2012). One objective of the present study is to address source of the salinity in the produced water, primarily using relationships between Na, Cl, and Br, and δ 18 

### O values in the time-series samples. 0 0

300 km

Greene Co. (southwest PA);Tioga and Lycoming Cos., (north central PA). 186 mi

Marcellus Shale Extent of Devonian Shale

Figure 1. Extent of Devonian shale and the Marcellus Shale (Middle Devonian) in the Appalachian basin (modified from Milici and Swezey 2006), and the counties in Pennsylvania (PA) where samples were collected for this study. U. Devonian shales (undiff.)

Mahantango Fm

Marcellus Sh Onondaga Ls

Helderberg Gp Salina Gp Ridgely Ss

Lockport Gp Clinton Gp Medina Gp
Queenston Gp

Trenton Ls

Beekmantown Gp

Gatesburg Fm Warrior Fm Reedsville Sh Utica Sh 

### Lithologic Unit

Sunbury Sh
Berea Ss

M. - L. Cambrian (undiff.) 

### SystemOrdovicianSilurianDevonian



### Miss. Penn. PermianCambrian 

### Upper

Middle

Lower

Upper

Upper

Upper Middle Lower

Lower

Middle Lower 

### Series

Dunkard Gp

Cuyahoga Gp Penn. (undiff.)

Sandstone Shale

Limestone

Dolomite Black shale Sandstone + Shale

Evaporitic sequence Venango Gp Bradford Gp Elk Gp

Burket shHamilton Gp

Huntersville Chert

Chert

Eroded Pottsdam Ss Black River LsNeedmore Sh

Figure 2. Generalized stratigraphy of the Permian

– Cambrian section in Pennsylvania (modified from stratigraphic columns published in Laughrey and Baldassare, 1998; Ryder, 2004, Carter, 2007; Repetski et al., 2008; Ryder et al., 2009; and Carter et al., 2011).

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### Geochemical evidence suggests that water produced from the Marcellus Shale over the long term (>1 yr)is likely to be formation water whose salinity originated predominantly from evaporative concentration of paleoseawater past the onset of halite precipitation. Studies of the Marcellus Shale have shown that it has very low porosity and permeability (Soeder, 1988; Lee et al., 2011), and it is considered by some to contain only negligible quantities of mobile water (e.g., Engelder, 2012a, b; Striolo et al., 2012). Immobile water would include, for example, water retained in small pores by high capillary pressure, and the irreducible water layer bound by Van der Waals forces to mineral surfaces (Passey et al., 2010). The assumption of only negligible amounts of mobile water in the Marcellus have raised the question of whether the produced water may in facthave been drawn from overlying or underlying reservoirs via natural or induced fractures. Ratios of radiogenic isotopes such as 228 

### Ra ∕ 226 

### Ra (this study) and
87 

### Sr ∕ 86 

### Sr (Chapman et al., 2012; Capo et al., 2014) address the question of the source reservoir of the water by identifying spec ific, relatively narrow ranges of values that characterize the water produced from the Marcellus Shale. The geochemical and isotopic data presentedhere provide insight into the origin of water and solutes in the Marcellus Shale, with implications for the subsurface movement of the brines as a result of hydraulic fracturing. The presence of the brines raises additional, as yet unanswered, questions about the hydrogeologic history of the Appalachian basin, including how dense brines were “ emplaced ” in Cambrian

– Devonian strata in the Appalachian 1 10 100TDS (mg/L) 

### (A)

(B)

(C)

(D) Well A, time-series sample

Well B, time-series sample Well C, time-series sample

1 10 100Na (mg/L)

1 10 100Cl (mg/L)

0 1 10 100 1000Br (mg/L)

Time (days) Well A, injected water

Well B, injected water

Well D, grab sample 0 25,000 50,000 75,000 100,000 125,000 150,000 175,000

0 10,000 20,000 30,000 40,000

0 20,000 40,000 60,000 80,000 100,000

100 200 300 400 500 600 700 800 900 1,000 Figure 3. Total dissolved solids (TDS) and ion concentrations versus time (days, measured from the first day of water flow from the wells) for Marcellus Shale wells in southwestPennsylvania. (A) TDS; (B) Na; (C) Cl; and (D) Br. Producedwater samples from the time-series wells A

– C, and grab sample,well D (plotted against the right axis) are shown as solid symbols. One stage of injected water from well A is shown as an open square, and seven stages of water injected water at wellB (open diamonds) are enclosed by a solid line. A sample collected on the first day of water flow at well B appears likely to represent the last stage of water injected water (see text). All injected water samples are plotted against the left axis. Solid line segments are best fit lines through the individual well data.

184 Geochemistry of Produced Water from Marcellus Shale Water, PA

### basin, and in particular how brines of this type entered the shales such as the Marcellus.

BACKGROUND Hydraulic Fracturing

Technological improvements in horizontal drilling and hydraulic fracturing over the last decade havemade it possible to produce gas in economic quantities from low-permeability formations such as the Marcellus Shale in the Appalachian basin and the Mississippian Barnett Shale in Texas (King, 2012a). After drilling a vertical well to the depth of the targethorizon, the borehole is steered to a horizontal direction; the horizontal continuation is often called alateral. Precisely positioned laterals are drilled horizontally for thousands of feet (hundreds to thousands of meters) within the most organic-rich and gas-rich interval in the formation following natural shifts in its depth. Holes at regular intervals in the steel casing of the lateral allow hydraulic fracturing to be carried out in multiple stages. As each stage is isolated, fluid is injected into the formation under pressures high enough to create a network of fractures. The fluid contains a proppant, a material such as fine-grained sand, which serves to prop open the fractures after the initially high pressure declines (King, 2012a). After all of the stages (typically eight or more) have been fractured, the well is opened allowing gas and water to flow to the surface. Pressures sufficient to fracture the shale are likely to exceed the capillary entry pressures of a range of pore sizes, allowing water to enter the poresin a process referred to as induced or forced imbibition (Byrnes, 2011; Roychaudhuri et al., 2011). The related phenomenon of spontaneous imbibition may also draw substantial amounts of water into the shale and has been concisely described by Engelder (2012a, p. 337) as “ a form of wicking madepossible by a high capillary pressure within the waterwet matrix of very fine grained rocks like gas shale. ” As pressures drop, water that has entered small poresby either form of imbibition may be retained indefinitely because a similar pressure gradient would be required to remove it (Byrnes, 2011; Engelder, 2012a, b). Before gas can be produced in high volumes, much of the water filling the borehole and the larger fractures must be d rained from the system (King, 2012b). The greatest flux of water to the surface occurs during the first few weeks of flowfrom the well, but decreases rapidly as gas production increases. The water produced from the wellsincludes the water injected for the hydraulic fracturing mixed with much higher salinity brine, which will subsequently be discussed. The term flowback is often used to refer to water returned to the surface during an arbitrary period, usually the first 1

– 2 weeks of production. For simplicity, we use produced water in this paper to indicate all water flowing from a well regardless of the timing.The Marcellus Shale wells sampled in southwest PA were fractured with water of approximately 50 ; 000 ± 20 ; 000 mg ∕ L TDS, composed of recycled produced water from nearby wells and diluted with freshwate r from surface sources. Improvements in technology have allowed for use of increasingly saline water, with TDS values as high as 70,000 mg/L (King, 2012a).

Cation Ratios

Brines with chemistries generally similar to theMarcellus Shale brines, with salinities derived predominantly from evaporated seawater, have been reported in formations of Cambrian

– Devonian age in the Appalachian basin (Poth, 1962; Breen et al., 1985; Siegel et al., 1990; Sanders, 1991; Dresel and Rose, 2010). Little is known about when the brines formed, except that they originated during a geologic period when evaporative conditions prevailed. A number of authors have inferred a genetic link between the residual brines associated with salt beds in the Salina Group (Silurian), and the occurrence of saline waters in other formations (e.g., Poth, 1962; Siegel et al., 1990; Dresel and Rose, 2010). Brines from the Salina are generally thought to have been expelled upward during sediment compaction, or as a result of tectonic stresses during the Alleghenian orogeny. This conceptual model appears logical, but it also remains possible that the saline formation waters formed during some other period when

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### evaporative conditions prevailed, possibly including the Permian. Paleogeographic reconstructions indicate that theAppalachian basin was situated at relatively low latitudes during the Permian (Scotese, 2000), within the zone compatible with an arid climate and evaporation. Arid conditions permitted thick evaporite sequences to form in western states such as Nebraska, Kansas, Oklahoma, Texas, and New Mexico (Jorgensen et al., 1996). To the east of the Appalachian basin, Permian evaporites occur in Great Britain (Meyer, 1965; Arthurton and Hemingway, 1972; Worley, 2005) as well as in continental Europe. It seems plausible that evaporitic conditions may also have prevailed in the Appalachian basin during the Permian. Until fairly recently the consensus was that themajor element composition of the oceans was essentially constant throughout the Phanerozoic (e.g., Rubey, 1951; Rittenhouse, 1967; Carpenter, 1978; Connolly et al., 1990; Stueber and Walter, 1991;and Hanor, 1994). However, studies of fluid inclusions trapped in marine halite have led other authorsto suggest that the major ion concentrations of seawater were not constant throughout the Phanerozoic (e.g., Das et al., 1990; Lowenstein et al., 2001; Horita et al., 2002). Seawaters during the Silurian, Devonian, and Jurassic are thought to have been enriched in Ca and depleted in Mg and SO 4 

### relative to modern seawater. Permian seawater, however, is considered to have differed only slightly from the modern composition (Horita, 1991). Both Das et al. (1990) and Horita et al. (2002) acknowledged that the composition of Silurian fluid inclusions could be adequately explained by the exchange of Ca and Mg during dolomitization. The apparent lack of extensive dolomitization in many evaporite basins led several authors (Lowenstein et al., 2001; Horita et al., 2002) to propose changes in the composition of seawater as a more general mechanism to explain the Ca-rich compositions of the fluid inclusions in Silurian halite, as well as the connate water incorporated in rocks of Silurian age. Hanor and McIntosh (2006, 2007) examined saline formation waters in the Michigan, Illinois, and Gulf Coast basins and concluded that evaporation of the Ca-enriched seawater discussed in Lowenstein et al. (2003) would nevertheless require significant additional dolomitization to account for the high Ca/Mg ratios in the formation water samples. Kharaka and Hanor (2014) discuss the strengths and weaknesses of the arguments for variation of major element chemistry in seawater through time, and provide a concise summary of the literature on this subject. Given some uncertainty as to the age of the water produced from the Marcellus Shale, and the presence of abundant dolomite in the Appalachian basin (Alling and Briggs, 1961), we have used themodern composition of seawater for purposes of discussion. We assume that th e compositional variations proposed for seawater of different ages would alter the detailed chemical evolution, but would not change the larger conceptual model of seawater evaporation, and subsequent need for additional dolomitization to increase in the Ca/Mg ratio, regardless of the seawater ’ s age. The relationships between Na, Cl, and Br during halite precipitation are expected to remain valid whether modern or ancient seawater is assumed.During seawater evaporation, a sequence of minerals precipitates as their individual saturation limitsare reached. Lithium is highly conservative and therefore not readily incorporated into these mineral phases. The concentration of Li has been shown to increase during evaporation to as much as 117 times its concentration in modern seawater (Zherebtsova and Volkova, 1966). In an important study of modern seawater, McCaffrey et al. (1987) used Li to track the degree of evaporation (DE), which they defined as molality of Li ð brine Þ 

### ∕ molality of Li ð seawater Þ 

### . At a DE of ∼ 13, for example, precipitation of calcium carbonate and gypsum has depleted Ca from modern seawater, and halite has reached saturation (McCaffreyet al., 1987; Figure 4). The term DE is used throughout the paper to refer to different degrees of seawater evaporation.
Na-Cl-Br Geochemistry

Relationships between Na, Cl, and Br in sedimentary basin formation waters have been widely used to investigate whether formation water salinity resulted from evaporative concentration of seawater (past threshold of halite saturation and onset of

186 Geochemistry of Produced Water from Marcellus Shale Water, PA

### precipitation), or alternatively from dissolution of halite (e.g., Carpenter, 1978; Siegel et al., 1990; Walter et al., 1990; Kharaka and Hanor, 2007). As seawater evaporates, halite precipitation removes Na and Cl ions from solution in a 1 ∶ 1 mole ratio.Na and Cl concentrations remain at the halite solubility threshold until nearly complete evaporation (DE of ∼ 98) when Na in the fluid has been almost entirely depleted (McCa ffrey et al., 1987). Bromide is almost entirely excluded from the lattice of halite and is rarely incorporated into other mineral phases allowing it to become increasingly concentrated in the residual brine during evaporation (Stoessell andCarpenter, 1986; McCaffrey et al., 1987). An average Br/Cl distribution coefficient of 0.032 for halite was determined by McCaffrey et al. (1987). Brinesformed from halite dissolution are therefore characterized by very low Br, whereas evaporated seawater is enriched in Br (Stoessell and Carpenter, 1986; McCaffrey et al., 1987; Walter et al., 1990). For an evaporating seawater, Na/Br and Cl/Br in the residual fluid plot as a trend with a constant slope (1 ∶ 1 in molar units) extending from seawater toward lower ratios (Walter et al., 1990). Halite dissolution yields Na/Br and Cl/Br ratios that increase along thesame trend away from seawater. The position of samples plotted relative to this trend is an indicator of whether salinity is derived from seawater evaporation or halite dissolution, or from an unrelated source (Stoessell and Carpenter, 1986; McCaffrey et al., 1987; Walter et al., 1990). In a study of brines in the Silurian Medina Sandstone, Sanders (1991) examined the possibleexternal sources of Br and found no viable alternatives to seawater evapor ation. Similar arguments would apply also to brines in the Devonian reservoirs if their formation waters had a common origin. It isalso unlikely that an external Br source would consistently reproduce the Na/Br and Cl/Br ratios that plot on or close to the trend for seawater evaporation (Figure 5). The relationships among Na, Cl, and Br are therefore considered reliable indicators of whether salinity originated from seawater evaporation versus halite dissolution.
Oxygen and Hydrogen Isotopes

During seawater evaporation, the heavier isotopes of oxygen and hydrogen, 18 

### O and 2 

### H, are progressively concentrated in the residual brine. Sofer and Gat (1975), for example, reported a δ 18 

### O value of +6.59 ‰ for bottom water in the Dead Sea, compared with a δ 18 

### O value of zero in standard mean ocean water (SMOW). Enrichment in 18 

### O and 2 

### H relativeto meteoric water is typical of brines in deep sedimentary basins, and indicates that some or all of the water DE~13

southwest PA north central PA DE~36.5 Evaporation 

### X =60%

(Mg)



### X =60% (Ca) 

### X =100% (Na+K) 

### Seawater Marcellus Shale:

Hypothetical diagenetic paths between evaporated seawater and produced water compositions 

### ?Wells A-D, southwest PA, median TDS ~158,000 mg/L

North central PA, median TDS ~278,000 mg/L Figure 4. Ternary plot showing median equivalent ratios of the major cations in water samples from the Marcellus Shale. Note that the Ca and Mg axes are truncated at 60%. Southwest Pennsylvania (PA) is represented by wells A

– D, and north central PA by 12 grab samples. By the onset of halite precipitation (DE ∼ 13), Ca has been depleted by precipitation of Ca-carbonates and gypsum; continued evaporation shifts the fluid composition along the (Na + K)-Mg axis toward greater Mg enrichment. The gray dashed lines are hypothetical diagenetic paths from the seawater evaporation trend toward the compositions measured in the produced water. Degree of evaporation (DE) is the factor by which conservative solutes are concentrated during seawater evaporation, and defined as molality of Li ð brine Þ ∕ molality of Li ð seawater Þ (McCaffrey et al., 1987). Evaporation data are from a study of modern seawater by McCaffrey et al. (1987).

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### has undergone evaporation (Kharaka and Hanor, 2007). Basinal brines plot to the right of the global meteoric water line (GMWL, Craig, 1961); if they have mixed with meteoric water, the heaviest δ 2 

### H and δ 18 

### O values likely represent the original, undiluted brine and a linear mixing trend extends toward the meteoric water line (Kharaka and Hanor, 2007, their figure 11). As evaporation continues to TDS concentrations exceeding ∼ 4 times seawater values, the trend toward heavier isotopes is reversed (Sofer and Gat, 1972, 1975; Holser, 1979; Kharaka and Hanor, 2007). The reversal in the isotopic trend can result in highly evaporated brines that are depleted in 18 

### O and 2 

### H relative to SMOW (Sofer and Gat, 1975; Moldovanyi and Walter 1992).

PREVIOUS STUDIES

Commercial exploitation of Appalachian basin brinesfor their salt content through the first half of the twentieth century accounts for much of the interest and (B)

Na/Br (mg/L) Well D, grab sample Well C, time-series sample

Southwest PA average Well A, time-series sample Well B, injected water Well B, time-series sample Well A, injected water Na/Br (mg/L) Seawater

Evaporation past halite saturation

Marcellus Shale, north central PA

Southwest PA average Seawater evaporated to DE ~36.5 Burket Shale, north central PA Halite dissolution

Na-enrichment Cl-enrichment Na-depletion
Cl-depletion Seawater evaporation trend 

### (A)



## + **+**

**+**

**+**

80 90 100 110 120 130 140 150 160

0 50 100 150 200 250 300 350Cl/Br (mg/L)Cl/Br (mg/L)

30 40 50 60 70 80 20 40 60 80 100 120 140 160 180 200 0 Figure 5. Na/Br versus Cl/Br forproduced-water samples superimposed on the modern seawater evaporation trend (solid gray line; McCaffrey et al., 1987). (A) North central Pennsylvania (PA) grab samples of Marcellus Shale produced water (solid triangles), and Burket Shale (U. Devonian, inverted solid triangle). The rectangular box shows the area ofthe plot below. (B) Southwest PA timeseries samples from wells A

– C and grab sample from well D (solid symbols). Samples of the water injected for hydraulic fracturing are shown as open symbols. Time-series samples shift toward greater Br-enrichment and lower Na/Br and Cl/Br ratios as indicated by the arrows, and converge on the area outlined by a heavy dashed line; the + symbol indicates the mean of the values within this area.

188 Geochemistry of Produced Water from Marcellus Shale Water, PA

### early literature on their chemistry (e.g., Mills and Wells, 1919; Stout et al., 1932; Price et al., 1937; Hoskins, 1947; McGrain and Thomas, 1951). Severalauthors have also presented the geologic and stratigraphic framework of oil and gas and brine reservoirs in the Appalachian basin (Price et al., 1937; Poth, 1962; Dresel and Rose, 2010). More recent studies have been motivated by the environmental challenges related to the management of the brine co-produced with oil and gas, as well as fundamental geologicquestions, such as the origin of the water and its salinity (e.g., Breen et al., 1985; Blauch et al., 2009; Soeder and Kappel, 2009). In a geochemical inves tigation of Marcellus Shale water samples, Blauch et al. (2009) reported major element chemistry (Na, Ca, Mg, K, Cl, SO 4 

### ,and alkalinity) in addition to Ba, Sr, and Fe for produced water from two Marcellus Shale wells in western and northeastern Pennsylvania, as well asfrom water treatment plants. Salinities for the individual wells after more than 30 days of production were in the range of 117,000 to 124,000 mg/L TDS. Significantly, the fluid salinity was thought possibly derived, at least in part, from dissolution of halite lenses plus calcite and other minerals observed along bedding planes in core from one of these wells (Blauch et al., 2009). Occurrences of halite in the Marcellus Shale have not been previously reported in the literature, but when present they would likely contribute to total salinity. The potential contribution of halite to total salinity in the samples analyzed by Blauch et al. (2009) is difficult to evaluate due to the absence of Br data. A study by Hayes (2009) represents an important geochemical data set for 19 Marcellus Shale wells in Pennsylvania and West Virginia, most of which were sampled at 1-, 5-, 14-, and 90-day intervals from theinitiation of production. Little geologic or geochemical interpretation accompanied the data; however, several aspects of the geochemistry of this study werediscussed by Haluszczak et al. (2013). They concluded based on Na-Cl-Br relationships, that the late flowback water represented in situ brines formed by evaporation of paleoseawater, and further noted thesimilarities in major element chemistries with samples from Devonian

– Ordovician reservoirs examined by Dresel and Rose (2010). Additional Marcellus Shale water analyses were published in a study ofthe hydrocarbon gas chemistry and light stable isotopes of water and gas in Devonian sandstones and shales in the northern Appalachian basin (Osborn and McIntosh, 2010). Several recent studies (Chapman et al., 2012; Capo et al., 2014; Kolesar et al., 2013) present new strontium isotopic data for water produced from the Marcellus Shale in southwest PA, as well as Upper Devonian

– Pennsylvanian sandstones and coals in the region; their well “ GR-A ” is well A in this study. The 87 

### Sr ∕ 86 

### Sr values of 0.7101 to 0.7121 characterizetheir Marcellus Shale water samples, whereas samples from Upper Devonian sandstones have markedly higher 87 

### Sr ∕ 86 

### Sr values of 0.7199 to 0.7209, despite generally similar TDS and major element chemistries (Dresel and Rose, 2010; Chapman et al., 2012).

METHODS Sample Collection

In Greene County, southwest PA (Figure 1), timeseries and grab samples were collected from gas producing wells within an area with a radius of about 2 miles (3.2 km). The Marcellus Shale in this region is at a depth of about 8000 ft (2.4 km). In Tioga and Lycoming Counties, north central PA, the wells were sampled over a lateral extent of ∼ 22 miles ( ∼ 35 km). These wells had been in production for 10 to 38 months, and the depth of the Marcellus Shale was typically ∼ 5500 ft ( ∼ 1.7 km), but ranged from 4000 to 8000 ft (1.2 to 2.4 km) due to folding and faulting. One sample was collected from a well producing gas from the Upper Devonian Burket Shale at a depth ofabout 4500 ft (1.4 km); this well had been in production for five months. The individual wells sampled for this study were selected by the authors, however, given the general difficulty in obtaining access for sampling, the choices were limited to wells operated by a small number of companies. Early in the time-series, samples were collected at the wellhead, but as the water flux dropped over time, it became necessary to collect samples from the gas

–water separator where methane and water accumulate. The separator is a low-oxygen to oxygen-free

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### environment at pressures near those of the wellhead. The water accumulated over a period of hours to days in the separators before being pumped into large water storage tanks. When water could not be obtained from the separator, samples were collected from the storage tanks where the water ’ s residence time was generally less than a week, depending on the water flux from the well. Small ports on the tops of the storage tanks are open to the atmosphere permitting oxidation of dissolved species and volatiles, if present, to degas; minor amounts of evaporation or dilution with rainwater would also be possible.Time-series samples in southwest PA were collected from three hydraulically fractured, horizontal wells A

– C. The samples were collected daily for the first week of flow, then at increasing time intervals for up to 20 months (see time scale in Figure 3). The TDS of the single sample of injected water obtained at well A was 70,600 mg/L (Figure 3A, Table 1). At well B, samples were collected from alleight injected water stages, although the geochemistry of the last stage could not be obtained. Analyses of the remaining seven stages yielded a TDS range of 23,000 to 50,000 mg/L. Samples of injected water were not obtained for well C, but were assumed similar to water injected at wells A and B given the limited number of water sources in the area. Grabsamples were also collected from hydraulically fractured vertical Marcellus Shale well D that had been producing gas for approximately 4 yr. Analyses of produced water from nearby conventional gas wells in Upper Devonian sandstones (this study), typically at depths of about 4500 ft. ( ∼ 1.4 km), are listed in Table 1 for comparison. On four occasions, samples were collected fromboth the separator and the storage tank (Table 1, samples A12, B12, GO2, and MO5). Differences in the TDS values of the pairs were modest (2%

– 7%), and, in all but one instance, TDS values were slightly higher in the separators than the storage tanks. To test for possible density stratification in the storage tanks, samples were collected at different depths using weighted bailers lowered through a port at the top of the tank. Minor differences in the TDS and sample chemistries were attributed to analytical variability, but no evidence of stratification was found. Water purged from an individual separator entered its storage tank through an inlet at the top, and fell to the water level in the tank creating turbulent mixing. We are therefore reasonably confident that water in thestorage tanks was homogeneous, and that its chemistry did not differ signifi cantly from water in the separator. During sample collection from the wellhead or the separator, or immediately after collection from the water storage tank, the samples were pumped through a 0.45 μ m (1.8 × 10

− 6 

### in.) canister filter containing fiber coated with acrylic co-polymer. An aliquot of the filtered sample was acidified with double distilled nitric acid for cation analyses.
Analytical Methods

The majority of the geochemical analyses were conducted in laboratories at the US Geological Survey (USGS); however, the early time-series samples from Well A (days 1

– 20), and samples of the water injected at well B were analyzed by the Department of Energy-National Energy Technology Laboratory (DOE-NETL) (Chapman et al., 2012; K. Schroeder, 2012, personal communication). In addition, several samples were analyzed by Activation Laboratories (Ontario, Canada). Comparisons of duplicate samples sent to multiple laboratories showed no marked differences. Quality control for the analyses was addressed by checking the charge balance and by comparing the results of duplicate samples. The majority of the data in Table 1 had charge balance errors <5% and nearly all were <10%. Analyses with errors ≥ 15% were discarded. Radium activities were determined by the USGS Radioisotopes Laboratory in Reston, Virgina, using Ba ð Ra Þ SO 4 

### precipitated from the samples, and analyzed by gamma-ray spectrometry using methods described in Kraemer (2005). Cation concentrations were determined by inductively coupled plasma

– optical emission spectroscopy (ICP-OES) and inductively coupled plasma

– mass spectrometry (ICP-MS), as indicated in Table 1. For selected samples from wells A and B, total alkalinity was determined by titration in the laboratory and is reported as HCO 3 

### . The remaining anion concentrations were determined by ion

190 Geochemistry of Produced Water from Marcellus Shale Water, PATable 1.Chemical Analyses of Produced-Water Samples*Approx.ReservoirDepth, ft(km)Na K B Li Mg Mn Fe Ba Ca Sr Br I Cl SO4HCO3Co CsCuNi Rb Pb ZnTDS(Calc.)mg/Lμg/LSampleNo. Sample Point Day ReservoirICPOESICP-OESICP-MSICP-MSICP-OESICP-OESICP-OESICP-OESICP-OESICP-OES ICICP-MS IC IC TITRICP-MSICP-MSICP-MSICP-MSICP-MSICP-MSICP-MS mg/LWELL A, GREENE COUNTY, SOUTHWEST PENNSYLVANIAA-I Injected Water–– –20,900 682 34.0 25.0 567 1.10 16.0 393 4,380 1,390 270 NA 41,900 63.0 NA 7.00 200 70 30 1,390<5 140 70,600A-1_WH Well head 1 Marcellus Shale 8000 (2.4) 26,000 275 20.6 51.4 776 2.12 43.7 1,110 6,530 1,400 313 NA 63,700<225 209 NA NA NA NA NA NA NA 100,000A-2_WH Well head 2 Marcellus Shale 8000 (2.4) 30,100 247 20.9 59.2 828 2.29 44.9 1,560 7,900 1,820 581 NA 65,000<225 193 NA NA NA NA NA NA NA 108,000A-3_WH Well head 3 Marcellus Shale 8000 (2.4) 26,800 258 22.2 61.3 866 2.38 49.2 1,490 7,370 1,720 543 NA 67,300<225 206 NA NA NA NA NA NA NA 106,000A-4_WH Well head 4 Marcellus Shale 8000 (2.4) 30,900 298 19.2 66.6 755 2.38 38.1 1,760 8,870 2,010 531 NA 70,200<225 192 NA NA NA NA NA NA NA 115,000A-5_WH Well head 5 Marcellus Shale 8000 (2.4) 28,300 309 19.3 68.0 762 2.29 1.10 1,640 7,950 1,870 608 NA 71,200<225 174 NA NA NA NA NA NA NA 113,000A-6_WH Well head 7 Marcellus Shale 8000 (2.4) 32,800 1,210 47.3 53.0 841 4.52 26.6 962 8,790 2,420 733 NA 81,900<225 98.8 NA NA NA NA NA NA NA 130,000A-7_WH Well head 15 Marcellus Shale 8000 (2.4) 32,400 308 16.5 83.0 953 3.01 28.1 2,270 9,630 2,280 668 NA 86,500<225 115 NA NA NA NA NA NA NA 135,000A-8_ST Storage tank 20 Marcellus Shale 8000 (2.4) 34,500 311 16.4 86.4 976 3.05 36.1 2,520 10,400 2,480 655 NA 87,700<225 116 NA NA NA NA NA NA NA 140,000A-9_ST Storage tank 212 Marcellus Shale 8000 (2.4) 43,800 281 NA 95.0 1,170 4.69 96.6 3,690 14,500 3,100 975 27.2 98,900<30 76.9<0.5 305 497 316 882<1 758 167,000A-10_ST Storage tank 297 Marcellus Shale 8000 (2.4) 39,200 251 NA 97.6 1,160 4.81 133 3,420 13,500 2,890 1,020 29.9 99,000<30 107 6.38 358 1,500 18,600 939 1.54 2,170 161,000A-11_ST Storage tank 393 Marcellus Shale 8000 (2.4) 40,300 290 15.6 95.9 1,510 4.83 107 3,360 14,300 2,890 981 NA 99,300<10 NA 25.3 343 640 347 917<10 960 163,000A-12_SEP Separator 438 Marcellus Shale 8000 (2.4) 40,400 280 16.4 96.2 1,410 5.80 194 3,970 14,200 3,130 954 NA 98,100<20 NA 16.0 260 500<20 840<10 1,100 163,000A-12_ST Storage tank 438 Marcellus Shale 8000 (2.4) 42,400 310 NA 10.7 1,440 5.90 174 4,150 14,800 3,260 984 NA 101,000<20 NA 22.0 290 550<20 940<10 990 169,000WELL B, GREENE COUNTY, SOUTHWEST PENNSYLVANIAB-I-a Injected Water–– –14,300 309 NA 25.9 440 1.03 0.523 NA 3,780 760 306 NA 30,200 124 NA NA NA NA NA NA NA NA 50,100B-I-b Injected Water–– –9,630 172 NA 17.2 306 0.787 2.58 NA 2,230 418 198 NA 19,200 603 NA NA NA NA NA NA NA NA 32,200B-I-c Injected Water–– –8,470 154 NA 14.9 291 0.844 1.45 NA 1,990 354 163 NA 15,500 774 NA NA NA NA NA NA NA NA 26,900B-I-d Injected Water–– –8,290 157 NA 14.9 277 0.801 1.01 NA 2,000 375 166 NA 16,700 608 NA NA NA NA NA NA NA NA 28,000B-I-e Injected Water–– –8,830 175 NA 15.9 285 0.810 0.272 NA 2,170 415 174 NA 18,200 458 NA NA NA NA NA NA NA NA 30,300B-I-f Injected Water–– –7,160 143 NA 12.6 218 0.587 0.101 NA 1,730 349 131 NA 13,900 250 NA NA NA NA NA NA NA NA 23,600B-I-g Injected Water–– –8,180 148 NA 12.9 221 0.407<1 NA 1,810 388 142 NA 15,000 57.2 NA NA NA NA NA NA NA NA 25,900B-1_WH Well head 1 Marcellus Shale 8000 (2.4) 8,170 178 NA 14.5 249 0.802 15.7 216 2,170 468 175 NA 16,800<4 364<0.5 67.4<20<30 382 1.80 129 28,500B-2_WH Well head 2 Marcellus Shale 8000 (2.4) 19,700 208 NA 43.9 535 1.84 40.1 549 5,030 946 444 NA 43,900<30 229<0.5 146 183<30 559<1 326 71,400B-3_WH Well head 3 Marcellus Shale 8000 (2.4) 21,800 222 NA 47.9 589 1.94 46.6 698 5,630 1,060 492 NA 48,200<30 207<0.5 155 200<30 589<1 459 78,800B-4_WH Well head 4 Marcellus Shale 8000 (2.4) 23,100 232 NA 50.9 633 2.15 56.4 818 6,240 1,180 497 NA 50,600<30 211<0.5 166 224<30 618<1 630 83,400B-5_WH Well head 5 Marcellus Shale 8000 (2.4) 24,000 228 NA 53.2 634 2.15 55.4 867 6,390 1,220 534 NA 52,400<30 193<0.5 170 227<30 615<1 382 86,400B-6_WH Well head 6 Marcellus Shale 8000 (2.4) 25,300 234 NA 54.7 668 2.27 59.8 981 6,950 1,340 568 NA 57,000<30 189<0.5 177 239 40.2 631<1 287 93,200B-7_WH Well head 8 Marcellus Shale 8000 (2.4) 27,600 257 NA 62.3 771 3.93 155 1,110 7,550 1,480 588 NA 61,100 25.3 181<0.5 161 225 53.6 593<1 348 101,000B-8_WH Well head 10 Marcellus Shale 8000 (2.4) 26,200 258 NA 61.9 797 2.96 90.5 1,140 7,510 1,480 623 NA 61,600<30 170<0.5 193 280 81.7 694<1 394 99,800B-9_SEP Separator 23 Marcellus Shale 8000 (2.4) 30,800 262 NA 75.6 899 3.20 106 1,690 9,580 1,970 717 19.9 72,300<10 134 1.43 270 386 2,830 868<1 1,360 118,000B-10_SEP Separator 43 Marcellus Shale 8000 (2.4) 32,500 271 NA 82.5 960 3.50 122 2,070 10,400 2,200 811 23.4 80,700<20 138 2.49 293 706 6,970 921 1 1,430 130,000B-11_SEP Separator 93 Marcellus Shale 8000 (2.4) 37,700 278 NA 93.7 1,210 4.93 148 3,040 12,700 2,720 794 28.1 66,700<20 135 5.39 337 1,570 19,200 935 2.89 2,110 125,000B-12_SEP Separator 189 Marcellus Shale 8000 (2.4) 37,750 310 24.0 93.3 1,480 4.40 173 2,960 13,450 2,770 951 NA 94,450<10 NA 19.5 335 525 245 965<10 1,040 155,000B-12_ST Storage tank 189 Marcellus Shale 8000 (2.4) 36,900 310 25.7 97.6 1,460 4.53 67.7 2,890 13,200 2,640 946 NA 93,500<10 NA 22.3 340 553 323 987<10 910 152,000B-13_ST Storage tank 234 Marcellus Shale 8000 (2.4) 42,300 320 21.1 97.4 1,410 5.00 192 3,720 13,800 3,140 945 NA 95,300<20 NA 13.0 250 650<20 910<10 970 161,000WELL C, GREENE COUNTY, SOUTHWEST PENNSYLVANIAC-1_WH Well head 1 Marcellus Shale 8000 (2.4) 12,400 128 19.0 28.0 268 1.70<1 439 2,910 447 283 NA 25,700<10 NA NA NA NA NA NA NA NA 42,600C-2_WH Well head 1.5 Marcellus Shale 8000 (2.4) 15,800 146 19.0 35.0 325 1.60 10.0 642 3,300 594 370 NA 33,400<10 NA NA NA NA NA NA NA NA 54,600(continued)

R OWAN ET AL

. 191Table 1.ContinuedApprox.ReservoirDepth, ft(km)Na K B Li Mg Mn Fe Ba Ca Sr Br I Cl SO4HCO3Co CsCuNi Rb Pb ZnTDS(Calc.)mg/Lμg/LSampleNo. Sample Point Day ReservoirICPOESICP-OESICP-MSICP-MSICP-OESICP-OESICP-OESICP-OESICP-OESICP-OES ICICP-MS IC IC TITRICP-MSICP-MSICP-MSICP-MSICP-MSICP-MSICP-MS mg/LC-3_WH Well head 2 Marcellus Shale 8000 (2.4) 16,400 152 20.0 36.0 347 1.60 18.0 696 3,520 637 379 NA 34,800<10 NA NA NA NA NA NA NA NA 57,000C-4_WH Well head 2.5 Marcellus Shale 8000 (2.4) 17,600 162 21.0 39.0 378 1.70 23.0 761 3,810 682 399 NA 37,000<10 NA NA NA NA NA NA NA NA 60,900C-5_WH Well head 3 Marcellus Shale 8000 (2.4) 18,400 171 21.0 40.0 397 1.70 24.0 800 4,000 714 409 NA 37,500<10 NA NA NA NA NA NA NA NA 62,500C-6_WH Well head 5 Marcellus Shale 8000 (2.4) 21,000 206 25.0 45.0 564 2.00 26.0 1,000 5,430 953 498 NA 46,200<10 NA NA NA NA NA NA NA NA 75,900C-7_WH Well head 6 Marcellus Shale 8000 (2.4) 24,400 243 27.0 51.0 686 2.60 50.0 1,270 6,400 1,160 568 NA 52,400<10 NA NA NA NA NA NA NA NA 87,300C-8_WH Well head 7 Marcellus Shale 8000 (2.4) 25,300 251 26.0 54.0 728 2.80 59.0 1,410 6,980 1,270 600 NA 55,800<10 NA NA NA NA NA NA NA NA 92,500C-9_WH Well head 8 Marcellus Shale 8000 (2.4) 26,700 259 26.0 57.0 785 2.80 52.0 1,560 7,430 1,380 617 NA 57,400<10 NA NA NA NA NA NA NA NA 96,300C-10_WH Well head 9 Marcellus Shale 8000 (2.4) 28,300 260 26.0 60.0 819 2.90 49.0 1,670 7,960 1,450 650 NA 60,500<10 NA NA NA NA NA NA NA NA 102,000C-11_WH Well head 10 Marcellus Shale 8000 (2.4) 28,500 263 25.0 61.0 853 3.10 52.0 1,730 8,370 1,480 675 NA 63,600<10 NA NA NA NA NA NA NA NA 106,000C-12_WH Well head 11 Marcellus Shale 8000 (2.4) 29,200 272 26.0 62.0 872 3.10 52.0 1,810 8,410 1,540 679 NA 64,400<10 NA NA NA NA NA NA NA NA 107,000C-13_WH Well head 46 Marcellus Shale 8000 (2.4) 35,400 319 27.0 79.0 1,150 4.40 103 2,810 11,700 2,240 850 NA 82,200<10 NA NA NA NA NA NA NA NA 137,000C-14_SEP Separator 79 Marcellus Shale 8000 (2.4) 37,200 311 24.0 84.0 1,280 5.20 132 3,210 12,700 2,470 927 NA 89,400<10 NA NA NA NA NA NA NA NA 148,000C-15_ST Storage tank 284 Marcellus Shale 8000 (2.4) 39,100 221 20.3 96.2 1,260 5.54 184 3,720 13,800 2,720 979 NA 92,300<60 NA 21.0 355 817<200 952<5 2,000 154,000WELL D, GREENE COUNTY, SOUTHWEST PENNSYLVANIAD-1_ST Storage tank–Marcellus Shale 8000 (2.4) 37,700 200 17.0 85.0 1,400 6.40 180 2,720 12,600 2,110 897 NA 91,000<.03<1 17.0 300 480 280 680<10 800 149,000D-2_ST Storage tank–Marcellus Shale 8000 (2.4) 39,400 230 14.5 85.3 1,330 6.90 164 3,030 12,800 2,380 889 NA 92,600<20 NA 39.0 230 390 30.0 630<10 710 153,000WELLS IN TIOGA & LYCOMING COUNTIES, NORTH CENTRAL PENNSYLVANIANE81 Separator–Marcellus Shale 4500 (1.4) 63,000 440 7.00 235 2,650 8.80 87.0 6,780 31,600 7,030 1,460 NA 167,000<20 NA NA NA NA NA NA NA NA 280,000CU82 Separator–Marcellus Shale 5000 (1.5) 57,400 590 9.00 245 3,670 9.20 110 3,780 35,700 5,460 1,470 NA 168,000<20 NA NA NA NA NA NA NA NA 276,000MA28 Separator–Marcellus Shale 4500 (1.4) 56,900 510 8.00 249 3,550 10.0 140 4,580 35,400 5,700 1,430 NA 166,000<20 NA NA NA NA NA NA NA NA 274,000SA14 Separator–Marcellus Shale 4000 (1.2) 63,100 430 6.00 233 2,730 23.0 180 16,500 37,100 10,300 1,400 NA 184,000<20 NA NA NA NA NA NA NA NA 316,000CO12 Separator–Marcellus Shale 5500 (1.7) 52,800 270 4.00 208 1,890 10.0 180 22,400 25,000 7,700 1,070 NA 146,000<20 NA NA NA NA NA NA NA NA 258,000NE13 Separator–Marcellus Shale 5500 (1.7) 57,900 440 5.00 263 2,380 14.0 140 19,800 34,000 8,940 1,210 NA 176,000<20 NA NA NA NA NA NA NA NA 301,000ST46A Separator–Marcellus Shale 5500 (1.7) 57,900 470 6.00 254 2,420 9.50 170 15,800 32,000 7,730 1,090 NA 166,000<20 NA NA NA NA NA NA NA NA 284,000ST46B1 Separator–Marcellus Shale 5500 (1.7) 44,800 240 5.00 198 1,460 5.20 150 12,400 19,000 5,170 780 NA 117,000<20 NA NA NA NA NA NA NA NA 201,000ST46B2 Separator–Burket Shale 4500 (1.4) 47,100 180<4 103 1,500 16.0 120 5,320 16,300 3,390 760 NA 109,000<20 NA NA NA NA NA NA NA NA 184,000FO72 Separator–Marcellus Shale 8500 (2.6) 56,300 440 5.00 243 1,610 24.0 200 20,300 27,700 8,100 1,040 NA 156,000<20 NA NA NA NA NA NA NA NA 272,000YO48 Separator–Marcellus Shale 6000 (1.8) 60,000 630 6.00 282 2,750 14.0 190 10,700 39,200 7,420 1,240 NA 180,000<20 NA NA NA NA NA NA NA NA 302,000PA50 Separator–Marcellus Shale 5500 (1.7) 60,000 380 10.0 254 2,190 12.0 140 19,200 29,500 8,120 1,240 NA 168,000<20 NA NA NA NA NA NA NA NA 289,000SH23 Separator–Marcellus Shale 5500 (1.7) 50,100 200<4 169 1,710 6.20 190 15,100 19,600 5,600 910 NA 128,000<20 NA NA NA NA NA NA NA NA 222,000WELLS PRODUCING FROM UPPER DEVONIAN SANDSTONES, GREENE COUNTY, SOUTHWEST PENNSYLVANIAGO2_SEP Separator–Bradford + Elk Gps. 4500 (1.4) 47,000 220 2.70 22.8 2,050 19.3 142 162 15,900 263 993 NA 108,000<20 ND 23.0 140 90.0 20.0 630 1,090<200 175,000GO2_ST Storage tank–Bradford + Elk Gps. 4500 (1.4) 52,600 230 2.00 25.7 2,190 19.4 156 201 17,500 296 1,070 NA 114,000 20.0 ND 19.0 170 150 90.0 790<10<200 188,000MC1_ST Storage tank–Bradford + Elk Gps. 4500 (1.4) 40,900 180 2.10 21.1 2,090 24.0 240 77.9 14,600 190 887 NA 96,700 21.0 ND 17.0 110 100 250 600 410<100 156,000MO5_SEP Separator–Bradford + Elk Gps. 4500 (1.4) 44,100 210 1.90 24.8 1,890 21.3 224 196 15,200 276 920 NA 99,100<20 ND 16.0 170 40.0 20.0 660<10 260 162,000MO5_ST Storage tank–Bradford + Elk Gps. 4500 (1.4) 39,800 190 2.30 25.3 1,990 20.1 170 189 14,600 240 916 NA 98,100<10 ND 16.0 200 50.0 240 670<10 140 156,000PR1_ST Storage tank–Bradford + Elk Gps. 4500 (1.4) 39,400 180 1.70 21.9 2,000 25.2 460 154 14,500 210 894 NA 96,500<10 ND 14.0 80.0 30.0 170 610<10<100 154,000PR3_ST Storage tank–Bradford + Elk Gps. 4500 (1.4) 47,400 230 2.30 25.4 1,950 26.6 519 104 16,300 228 1,000 NA 109,000<20 ND 16.0 90.0 40.0 20.0 640 28<200 177,000*NA, not analyzed; ND, not detected. Analytical methods: ion chromatography (IC), inductively coupled plasma–optical emission spectroscopy (ICP-OES), inductively coupled plasma–mass spectrometry (ICP-MS), and total alkalinity, as HCO3, determined by titration (TITR). TDS = total dissolved solids.

192 Geochemistry of Produced Water from Marcellus Shale Water, PA

### chromatography (IC). In all but one sample, SO 4 

### measurements were below t he analytical detection limits (0.03

– 225 mg/L). The detection limits variedbetween samples and laboratories due to the low initial SO 4 

### concentrations in th e produced water, and large amounts of sample dilution needed to bring more concentrated analytes into measurable ranges (Table 1). The Fe content of the samples may have been affected by dissolution of Fe from the steel casing in the well, as noted by Dresel and Rose (2010). At the wells we sampled, the separator tanks had an interior coating of porcelain, and the produced-water storage tanks were constructed of a fiberglass material. However, Fe and Mn concentrations may also have been compromised because of the formation of oxides or adsorption of these metals onto clay particles small enough to pass through a 0.45 μ m (1.8 × 10

− 6 

### in.) filter and dissolve in an acidified sample. Ideally, a 0.1 μ m (3.9 × 10

− 6 

### in.) filter should be used for samples collected for analysis of Fe, Mn, and other trace metals (Y. Kharaka, 2013, personal communication). For these reasons, the analytical results for Fe and Mn, and possibly other trace metals reported in Table 1 should be interpreted with caution. Oxygen and hydrogen isotopic ratios of water were analyzed at the USGS Stable IsotopesLaboratory, in Reston, Virginia. A hydrogen equilibration method was used to determine δ 2 

### H, and δ 18 

### O was determined by CO 2 

### equilibration (Révész and Coplen, 2008a, b). These methods yielded results as activities that were converted to concentrations using the equations of Sofer and Gat (1972, 1975). These authors showed that differences between the activity and the concentration of 18 

### O and 2 

### H increase with increasing salinity. The corrections were madeto allow comparison of our data with previously published isotope data, much of which was determined by analytical methods that yield concentrationsdirectly. Table 2 shows both the activities (uncorrected) and the concentratio ns (corrected); only theconcentrations were used in plotting figures. The isotopic data are reported in per mil notation relative toVienna standard mean ocean water (VSMOW) standard; one standard deviation of measurement uncertainty is equal to 0.1 ‰ for δ 18 

### O and 1 ‰ for δ 2 

### H (Coplen and Kendall, 2000). RESULTS AND DISCUSSION Na-Cl-Br Geochemistry

In north central PA, Na/Br and Cl/Br ratios of the samples plot on or close to the seawater evaporation trend (Figure 5A). In the time-series samples from southwest PA, Na/Br and Cl/Br shift with time from the ratios of the injected water toward the seawater evaporation trend, and converge on a small region slightly below the trend (Figure 5B). These shifts are interpreted as the transition from primarily injectedfluid toward the composition of Marcellus Shale formation water. Because they are relatively tightly clustered, the southwest PA samples are represented here by an average value (plus symbol, Figure 5A, B). The average was calculated from the last three values in the time-series at wells A and B, the last sample from well C, and the average of two grab samples well D. The elevated bromide content of the Marcellus brines from southwest PA (median of 956 mg/L) and from north central PA (median of 1225 mg/L), and Na/Br and Cl/Br ratios that plot on or close tothe seawater evaporation trend, are considered diagnostic evidence for seawater evaporation as the predominant source of the brine ’ s salinity (Carpenter, 1978; Walter et al., 1990; Dresel and Rose, 2010). Small deviations from the seawater evaporation trend are usually attributed to diagenetic reactions suchas albitization of plagioclase and formation of Nabearing clays that may deplete Na from the fluid (Carpenter, 1978; Nesbitt, 1985; Stueber and Walter, 1991), or formation of chlorite that may deplete Cl from the fluid (Graf et al., 1966; Dresel and Rose, 2010).

Relationships among Major and Selected Trace Elements

The salinities of the different stages of injected water at wells A and B, southwest PA, ranged from 24,000 to 71,000 mg/L, with a median of 29,000 mg/L TDS. After hydraulic fracturing, wells A

– C were opened to water and gas flow and the samples initially showed initial large daily increases in TDS, Na, Cl, and Br (Figure 3A

– D); the increases continued linearly with the log of time (days) until a plateau was reached after

R OWAN ET AL

. 193Table 2. Activity and Concentration Values of δ 18 O and δ 2 H for Produced-Water Samples

δ 2 H ( ‰ ) δ 18 O ( ‰ ) δ 2 H ( ‰ ) δ 18 O ( ‰ ) Sample No. Sample Point Day Activity Concentration
WELL A, GREENE COUNTY, SOUTHWEST PENNSYLVANIA A-I Injected Water

– − 40.3

− 3.89

− 41.6

− 3.78 A-1 Well head 1

− 40.4

− 2.65

− 42.1

− 2.53 A-2 Well head 2

− 39.9

− 2.62

− 41.9

− 2.48 A-3 Well head 3

− 40.2

− 2.60

− 42.1

− 2.47 A-4 Well head 4

− 40.3

− 2.46

− 42.5

− 2.32 A-5 Well head 5

− 40.4

− 2.51

− 42.4

− 2.38 A-6 Well head 7

− 40.4

− 2.35

− 42.6

− 2.21 A-7 Well head 15

− 40.0

− 2.10

− 42.4

− 1.93 A-8 Well head 23

− 39.1

− 2.06

− 41.6

− 1.88 A-9a Storage tank 210

− 36.8

− 1.96

− 40.3

− 1.72 A-9b Storage tank 212

− 36.1

− 1.95

− 39.6

− 1.71 A-10 Storage tank 297

− 37.3

− 2.05

− 40.6

− 1.82 A-11 Storage tank 393

− 37.3

− 2.11

− 40.8

− 1.86 A-12 Separator 438

− 38.5

− 2.19

− 41.9

− 1.94 A-13 Storage tank 577

− 39.2

− 2.10

− 42.6

− 1.85 A-14 Storage tank 610

− 38.6

− 2.23

− 42.1

− 1.98
WELL B, GREENE COUNTY, SOUTHWEST PENNSYLVANIA B-I-a Injected Water

– − 36.3

− 4.03

− 37.2

− 3.97 B-I-b Injected Water

– − 36.6

− 4.63

− 37.2

− 4.59 B-I-c Injected Water

– − 36.8

− 4.52

− 37.4

− 4.48 B-I-d Injected Water

– − 35.9

− 4.66

− 36.4

− 4.62 B-I-e Injected Water

– − 37.5

− 4.61

− 38.1

− 4.57 B-I-f Injected Water

– − 41.2

− 5.50

− 41.7

− 5.47 B-I-g Injected Water

– − 40.3

− 5.36

− 40.8

− 5.33 B-1 Well head 1

− 42.5

− 5.68

− 43.0

− 5.64 B-2 Well head 2

− 34.6

− 3.02

− 35.9

− 2.94 B-3 Well head 3

− 35.8

− 2.92

− 37.2

− 2.83 B-4 Well head 4

− 35.4

− 2.77

− 36.9

− 2.67 B-5 Well head 5

− 35.0

− 2.72

− 36.6

− 2.61 B-6 Well head 6

− 35.1

− 2.66

− 36.9

− 2.54 B-7 Well head 8

− 34.8

− 2.52

− 36.6

− 2.39 B-8 Well head 10

− 35.9

− 2.62

− 37.8

− 2.49 B-9 Separator 23

− 34.2

− 2.15

− 36.5

− 1.99 B-10 Separator 43

− 33.9

− 1.96

− 36.4

− 1.79 B-11 Separator 93

− 35.3

− 1.91

− 38.1

− 1.71 B-12 Separator 189

− 36.0

− 1.85

− 39.3

− 1.61 B-13 Storage tank 234

− 36.9

− 2.02

− 40.0

− 1.80 B-14a Separator 373

− 37.5

− 1.99

− 40.7

− 1.77 B-14b Storage tank 373

− 39.0

− 2.09

− 42.1

− 1.87 B-15a Well head 406

− 35.5

− 1.61

− 38.7

− 1.39 B-15b Storage tank 406

− 40.6

− 2.29

− 43.7

− 2.07 ( continued )

194 Geochemistry of Produced Water from Marcellus Shale Water, PA

### approximately 7

– 12 months. The maximum TDS values measured in the produced water were 168,000 mg/L at well A, 161,000 mg/L at well B, and 154,000 mg/L at well C. The average TDS of two grab samples from well D was 151,000 mg/L. When the produced-water composition stabilizesin southwest and north central PA, it is a Na-Ca-Cltype brine. Cl represents nearly 100% of the anions, with minor to insignificant fractions of SO 4 

### and HCO 3 

### (Table 1). The median SO 4 

### concentration ofthe injected water at well B was 460 mg/L, but its concentration decreased in the time-series samples, with one exception (25.3 mg/L), to below detection limits of 4 to 30 mg/L (Table 1), suggesting that the primary Table 2. Continued

δ 2 H ( ‰ ) δ 18 O ( ‰ ) δ 2 H ( ‰ ) δ 18 O ( ‰ ) Sample No. Sample Point Day Activity Concentration
WELL C, GREENE COUNTY, SOUTHWEST PENNSYLVANIA

C-1 Well head 1

− 34.8

− 2.91

− 35.4

− 2.87 C-2 Well head 1.5

− 34.1

− 2.39

− 34.8

− 2.34 C-3 Well head 2

− 34.1

− 2.35

− 34.8

− 2.29 C-4 Well head 2.5

− 34.3

− 2.45

− 35.1

− 2.39 C-5 Well head 3

− 33.7

− 2.45

− 34.6

− 2.38 C-6 Well head 5

− 38.0

− 3.04

− 39.1

− 2.95 C-7 Well head 6

− 35.6

− 2.80

− 36.9

− 2.69 C-8 Well head 7

− 37.3

− 2.73

− 38.7

− 2.61 C-9 Well head 8

− 36.2

− 2.69

− 37.6

− 2.57 C-10 Well head 9

− 35.3

− 2.61

− 36.9

− 2.48 C-11 Well head 10

− 35.9

− 2.46

− 37.5

− 2.32 C-12 Well head 11

− 35.8

− 2.52

− 37.4

− 2.38 C-13 Well head 46

− 34.8

− 2.03

− 37.0

− 1.83 C-14 Well head 79

− 35.7

− 2.02

− 38.1

− 1.79
WELL D, GREENE COUNTY, SOUTHWEST PENNSYLVANIA D-1 Storage tank

– − 32.2

− 1.82

− 35.2

− 1.60 D-2 Storage tank

– − 33.1

− 1.81

− 35.7

− 1.63
WELLS IN TIOGA & LYCOMING COUNTIES, NORTH CENTRAL PENNSYLVANIA
NE81 Separator

– − 35.8

− 1.86

− 43.0

− 1.53 CU82 Separator

– − 35.8

− 1.86

− 43.0

− 1.28 MA28 Separator

– − 37.0

− 2.12

− 44.2

− 1.54 SA14 Separator

– − 36.5

− 1.08

− 43.9

− 0.52 CO12 Separator

– − 44.0

− 2.68

− 49.1

− 2.30 NE13 Separator

– − 37.3

− 1.35

− 44.0

− 0.84 ST46A Separator

– − 36.8

− 1.57

− 43.2

− 1.09 ST46B1 Separator

– − 42.5

− 3.00

− 46.5

− 2.71 ST46B2 Separator

– − 38.1

− 3.02

− 42.0

− 2.76 FO72 Separator

– − 37.2

− 1.78

− 44.0

− 1.91 YO48 Separator

– − 35.9

− 1.10

− 43.6

− 0.52 PA50 Separator

– − 35.7

− 1.26

− 41.7

− 0.82 SH23 Separator

– − 38.4

− 2.31

− 41.5

− 1.47

R OWAN ET AL

. 195

### SO 4 

### source was the water used for hydraulic fracturing. King (2012b, his figure 1) indicates that declining SO 4 

### concentrations in the w ater produced immediately after hydraulic fracturing can be used to track the fraction of injected fluid in the water. Dresel andRose (2010) provided evidence of reducing conditions that imply very low SO 4 

### concentrations in the Lower Silurian

– Upper Devonian sandstone reservoirs that they sampled. Even given the limited amounts of water in the Marcellus Shale, we would anticipatesimilarly reducing conditions. The high Ba concentrations ultimately measured in the produced water from the Marcellus Shale (10 3 

### to 10 4 

### mg ∕ L) also imply very low natural concentrations of dissolved SO 4 

### in the reservoir due to the low solubility of barite (Ksp ∼ 10

− 10 

### ; Monnin, 1999). A limited number of measurements of HCO 3 

### were made in the time-series samples from wells A and B. However, HCO 3 

### analyses are not available for the injected water. The general decrease in HCO 3 

### concentration from 364 to <100 mg ∕ L in the timeseries suggests that its primary source, like SO 4 

### , was from the water injected for hydraulic fracturing. Similar observations of declining HCO 3 

### and SO 4 

### were reported by Blauch et al. (2009) in analyses of time-series samples, and Dresel and Rose (2010) reported low HCO 3 

### concentrations (<200 mg ∕ L) in brine samples from reservoirs of Lower Silurian to Upper Devonian age in the Appalachian basin. In the early stages of seawater evaporation, Ca, SO 4 

### , and HCO 3 

### concentrations are reduced primarily by precipitation of calcium carbonates and gypsum.In the shallow subsurface prior to deep burial, microbial sulfate reduction is also likely to play a role in depleting SO 4 

### (Siegel et al., 1987; Schoonen, 2004). Depletion of Ca caused by precipitation of calcite carbonate and gypsum is followed by the onset of halite precipitation; at this point, the solutes have been concentrated by a factor of approximately 13 or a DE of ∼ 13 in modern seawater (McCaffrey et al., 1987). The onset of halite precipitation plots on the(Na + K) - Mg axis (Figure 4). Continued evaporation and halite precipitation shift the composition of the residual fluid along this axis toward the Mg apex as Na is depleted (Figure 4). Relative to evaporated s eawater, all of our produced-water samples are enriched in Ca and depleted in Mg (Figure 4; Table 1). T his pattern is consistentwith basinal brines derived from evaporatively concentrated seawater that have been modified by commonly occurring diagenetic reactions (Carpenter, 1978; Sanders, 1991; Dresel and Rose, 2010). Therecrystallization of carbonates to form dolomite represents a primary source for Ca and a sink for the concentrated Mg in the residual evaporated fluid. Mg may also be depleted by formation of chlorite and alteration of illite to chlorite (Graf et al., 1966; Stueber and Walter, 1991). Reactions with feldspars and clays including albitization of Ca-plagioclase and conversion of illite to smectite, may exchange Ca for Na, and shift the ratios of these cations (Graf et al., 1966; Carpenter, 1978; Sanders, 1991; Stueber and Walter, 1991; Dresel and Rose, 2010).When Na + K, Ca, and Mg are plotted as equivalent fractions, samples from wells A-D in southwest PA are virtually indistinguishable from one another, as are the 12 Marcellus Shale samples from northcentral PA (Figure 4). Both regions have similar fractions of Mg, but the equivalent fractions of ð Na + K Þ ∕ Ca are >20% higher in southwest PA (Figure 4). The fraction of K is low and relatively consistent in the samples from both regions (Table 1), and the Na/Ca ratio is the primary factor differentiating the samples shown on the ternary plot (Figure 4). After evaporation has ceased, dolomitization of calcium carbonates is the primary reaction to shift the Mg-rich residual brine to the more Ca-rich composition of the samples (Carpenter, 1978). The smaller equivalent fraction of Na + K in north central PA may have resulted from differences in diagenetic history, including factors such as the degree of Na depletionthrough evaporation, or the extent of diagenetic reaction with clays and feldspars, or Ca-enrichment through dolomitization. Several lines of evidence indicate that samples from both southwest and north central PA have mixed during their history with a more dilute fluid, possibly including a brine derived from halite dissolution. Samples in southwest and north central PA have median TDS concentrations of 158,000 and 278,000 mg/L, respectively, compared with ≥ 330,000 mg/L in evaporating seawater at halite saturation and throughout the precipitation process (McCaffrey et al., 1987). Dilution of evaporated

196 Geochemistry of Produced Water from Marcellus Shale Water, PA

### seawater after the onset of halite precipitation to the TDS concentrations of the samples would also reduceBr to below the concentrations measured in the samples. For southwest PA, we therefore investigated the amount of dilution needed at several points fartheralong the evaporation path (Figures 4, 5A) to approximately match the TDS and Br content of the samples. In southwest PA, the median TDS (158,000 mg/L) and Br (956 mg/L) concentrations can be approximately matched by seawater evaporated to a DE of ∼ 36.5, diluted with fresh water by 56%, basedon the data of McCaffrey et al. (1987). Less evaporated seawater cannot be diluted to the observed TDS values without “ over-diluting ” Br. Given the caveat that only Br and TDS have been taken into account, it would appear that the seawater component of these samples is likely to have been evaporated to at least a DE of 36.5. Siegel et al. (1990) reached a similar conclusion for brine samples from the Medina Sandstone (Silurian) in southwest New York. Based on Na, Cl, and Br relationships and δ 18 

### O and δ 2 

### H values, they concluded that the brine ’ s salinity originated from seawater that had evaporated to about 40 times its original concentration prior to dilution. In north central PA, seawater evaporated to a DE of ∼ 36.5 and diluted with fresh water by ∼ 20%would approximately match the median Br concentration (1225 mg/L) of the samples. However, theresulting TDS would be about 20% below the measured median value of 278,000 mg/L. One possible solution would be mixing between the evaporative brine and a less Br-enriched fluid such as seawater, or fluid with salinity derived from halite dissolution. Among individual samples, the range along the evaporation trend is consistent with locally variable contributions to salinity from halite dissolution. Such contributions would have shifted the Na/Br and Cl/Br ratios from their values when evaporation ceased (e.g., a DE of ∼ 36.5, open circle in Figure 5A), upward along the evaporation trend to the measured values. The similarities in the Na/Br and Cl/Br ratios of samples from southwest and north central PA (Figure 5A), suggest that the brines evolved through similar processes of seawater evaporation, mixing with more dilute fluid, and diagenetic modification, primarily dolomitization, which increased the Ca/Mg ratios. Dilution is also required to account for undersaturation of halite in the fluids, despite evidence of evaporation beyond the onset of halite precipitation in the original brine. We speculate that the two groups of samples originated during a period when arid conditions favoring evaporation prevailed over a broad area, but with local variations. For example, unconnected or poorly interconnectedbasins may have had differing histories of evaporation resulting in residual brines with distinctive cation concentrations. Alternatively, brines from different localities, such as southwest and north central PA, may have had similar evaporation histories, but laterunderwent differing degrees of dilution and diagenetic modification.
Oxygen and Hydrogen Isotopes

The δ 18 

### O and δ 2 

### H values of samples from southwest and north central PA plot to the right of the global meteoric water line in the region typical of deep basin brines (Figure 6; Kharaka and Hanor, 2007). The range of δ 18 

### O values of both regions overlap, but the median in north central PA (

− 1.4 ‰ ) is more enriched in 18 

### O than the median in southwest PA (

− 1.7 ‰ ); both medians were calculated for samples collected from separators after at least seven months of production. The δ 18 

### O and TDS values are correlated in each region and are discussed at the end of this section. On the first day that well A (southwest PA) was opened to flow, the δ 18 

### O values shifted from the injected water value of

− 3.8 to

− 2.5 ‰ , but the δ 2 

### Hvalues were unchanged (Figure 7; Table 2). The magnitude of the shifts in δ 18 

### O decreased over time until reaching a plateau at about

− 1.85 ± 0.2 ‰ . At well B, the δ 18 

### O value on the first day of production was

− 5.7 ‰ , and a pronounced shift did not occur until the second day (Figure 7). The sample from day 1 clearly appears to be compositionally more closelyassociated with the injected water than the water produced in subsequent samples (Figures 6, 7, 8). The first water returned to the surface contains the greatest fraction of injected water (King, 2012a, b), and consists predominantly the water injected during the

R OWAN ET AL

. 197

### last stage of hydraulic fracturing. We assume that the day 1 sample from well B reflects the composition of the final stage of injected water, and calculate a median δ 18 

### O value of

− 4.6 ‰ for all stages of the injected water at this well. The sample collected on the second day of production had a δ 18 

### O value of − 2.9 ‰ , and subsequent samples more gradually reached a plateau of

− 1.75 ± 0.4 ‰ . The last sample in the time-series at well C, collected after only 79 days of production, yielded a δ 18 

### O value of

− 1.8 ‰(Figure 7; Table 2). Thus, after less than a year of production, the water sampled from wells A, B, and C GMWL

-10 -9 -8 -7 -6 -5 -4 -3 -2 -1 0 18 O, H 2 O (‰, VSMOW) δ2H, H O (‰, VSMOW)δ Well A, injected water Well A, time-series Well B, injected water Well B, time-series Well C, time-series Well D, grab sample Spring water

North central PA: Southwest PA:2

Burket shale, Marcellus Shale grab samples Meteoric water from Pennsylvania

Oxygen isotope trend

-70 -60 -50 -40 -30 -20 Figure 6. δ 18 O versus δ 2 H for produced-water samples (solid symbols). Southwest Pennsylvania (PA): the dashed gray arrow indicates progression in samples from wells A

– C toward the final values in the times series (enclosed by the heavy dashed line); well D is included for comparison. Injected water from well A is shown by the open square. Seven stages of injected water from well B (open diamonds), and the sample from its first day of production (solid diamond) are enclosed by a solid line (see text). North central PA: grab samples from the Marcellus Shale (solid triangles); Burket Shale sample (inverted solid triangle). Surface water isotopic values for Pennsylvania (open circles; Coplen and Kendall, 2000) are superimposed on the global meteoric water line (GMWL; Craig, 1961).

0 1 10 100 1,00018O, H2O (‰, VSMOW)

Time (days) Well A, injected water

Well C, time-series Well B, injected water
Well B, time-series

Well Dδ Well A, time-series

-6 -5 -4 -3 -2 -1 Figure 7. δ 18 O versus time (days, measured from the first day of water flow from the wells). Marcellus Shale time-series samples from wells A

– C (solid symbols); grab sample from well D (solid symbol). Injected water from well A is shown by an open square. Samples from seven stagesof injected water from well B (open diamonds) are enclosed by a solid line. A sample collected on the first day of water flow appears likely to represent the last stage of water injected water at well B (see text and Figure 3). Error bars represent
± 0.2 ‰ δ 18 O.

198 Geochemistry of Produced Water from Marcellus Shale Water, PA

### had converged on δ 18 

### O values between approximately

− 1 and

− 2 ‰

. The δ 2 

### H values were consistently in the range of

− 40 ± 5 ‰ in the time-series samples, and in all but two of the grab samples. This observation, and the absence of a correlation between δ 2 

### H and TDS, might be explained by hydraulic fracturing with water recycled from the Marcellus Shale and Upper Devonian sandstone gas wells, both with δ 2 

### H values of

− 40 ± 5 ‰ , and diluted by local meteoric water whose δ 2 

### H range overlaps that of the produced water samples. This explanation is consistent with Dresel and Rose (2010) who reported that the δ 2 

### H valuesof their samples were, with one exception, consistently in the

− 40 ± 5 ‰ range despite originating from different formations. Although strongly positive δ 18 

### O and δ 2 

### H values occur during the early stages seawater evaporation, the isotopic reversal, which occurs with continued evaporation (e.g., Sofer and Gat, 1972, 1975;Holser, 1979), may plausibly explain highly evaporated brines that are isotopically depleted relative to SMOW. The δ 2 

### H values in virtually all of our samples are in the

− 40 ± 5 ‰ range, whereas the heaviest δ 18 

### O value measured in this study is

− 0.52 ‰ . Therefore, dilution or mixing does not appear to be required to account for the δ 18 

### O and the δ 2 

### H values, but it is likely to have occurred based on the salinity observations discussed in the previous section. Significant oxygen isotope exchange between the injected water and minerals in the reservoir rocks via mineral dissolution would not be expected to occuron a time scale of years or less, particularly given reservoir temperatures of approximately 75°C (167°F) at depths of 8000 ft (2.4 km) in wells A, B, and C (Anderson and Chai, 1974; O ’ Neil and Kharaka, 1976). Therefore, the produced water could not be interpreted as injected water returned to the surface with heavier δ 18 

### O values related to rock

– water interaction. Rather, the 18 

### O enriched water is interpreted to be formation water rele ased from the Marcellus Shale. In the time-series samples in southwest PA, δ 18 

### O and TDS shift progressively toward isotopically heavier and more concentrated values that are common in basinal brines (Figures 3, 7, 8). The shifts suggest a mixing trend between the injected fluid and a distinct, so-called indigenous fluid. The short time frame (days) of the initial shift in TDS and δ 18 

### O is consistent with imbibition of a significant fraction ofthe injected water, effectively removing it from circulation. Subsequent, more gradual shifts in δ 18 

### O and TDS are interpreted as continued mixing and flushing of the remaining injected water from the system (Figures 3, 7, 8). The simultaneous shifts in the

-6 -5 -4 -3 -2 -1 0

0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 Well B, time-series
Well D, grab sample Well A, Injected water

Well B, injected water

Well C, time-series Well A, time-series -18O, H2O (‰,VSMOW)δ grab samples Figure 8. δ 18 O versus TDS for Marcellus Shale samples. Southwest Pennsylvania (PA): time-series samples of produced water from wells A

– C andgrab sample from well D (solid symbols). Injected water samples are shown as open symbols. North central PA: grab samples from Marcellus Shale wells (solid triangles). Differences between the slopes of the trends are discussed in the text.

R OWAN ET AL

. 199

### Na/Br and Cl/Br ratios toward the seawater evaporation trend support the interpretation of mixing between the injected water and a distinct second fluidwhose salinity originated predominantly from evaporated seawater. The TDS and δ 18 

### O values are also correlated in the grab samples from north central PA (Figure 8). The Marcellus Shale wells sampled in this area had been in production for 10 to 38 months, so we do not expect that the TDS- δ 18 

### O correlation is relatedto mixing between the water used for hydraulic fracturing and formation brine. The correlation may instead result from differing degrees of evaporation of the original brine, as well as differing degrees ofmixing between the evaporative brine and an isotopically lighter, more dilute fluid. In southwest PA, the endmember values in the time-series samples (wells A

– C), and well D, aretightly clustered in comparison with the grab samples from north central PA, consistent with the closer spacing of the wells from southwest PAwithin a radius of about 2 miles (3.2 km). The samples from north central PA extend over ∼ 22 miles ( ∼ 35 km) trend. Differences between the slopes and equations of the best-fit lines for the two regions (Figure 8) are likely the result of the very different types of mixing, as described in the paragraph above. The significantly higher TDS and δ 18 

### O values in the north central PA samples, relative to the time-series end-member values in southwest PA, are interpreted to indicate regional differences in the diagenetic histories of the fluids in the two regions.

Radium

Like most of the other solutes, radium levels increase rapidly in the first days of production, then more gradually with time. At well A, 226 

### Ra activity reaches a plateau at approximately 9500 pCi/L after about 12 months of production (Figure 9). The
228 

### Ra ∕ 226 

### Ra ratio in the produced water reflects the abundances of their respective parent isotopes,
232 

### Th and 238 

### U, in the reservoir rocks, and the ratio can be used as indicator of reservoir lithology (Adams and Weaver, 1958; Cowart and Burnett, 1994; Kraemer and Genereux, 1998). Analysis of the sample of injected water sample at well A yielded

a 228 

### Ra ∕ 226 

### Ra ratio of 0.23. This ratio dropped during the first few days of production to a relatively stable value of ∼ 0.12; a slightly lower ratio of

∼ 0.09 was measured at well B. In contrast, waters produced from sandstone reservoirs worldwide most commonly have 228 

### Ra ∕ 226 

### Ra ratios of 1 to 1.6 (Vengosh et al., 2009). Based on the limited data available for the Appalachian basin, the median
228 

### Ra ∕ 226 

### Ra ratio for sandstones was ∼ 0.8 (Rowan et al., 2011).

R = 0.98

R = 0.97 2,000 4,000 6,000 8,000 10,000

1 10 100 1,000Activity (pCi/L)

Ra Activity, Well A (left axis)

226
Ra 228

0 Time (days) 0 25,000 50,000 75,000 100,000 125,000 150,000 175,000TDS (mg/L) Produced water TDS, Well A (right axis)

Injected water Injected water Figure 9. Total dissolved solids (TDS), 226 Ra, and 228 Ra activities versus time (days, measured from the first day of water flow from the well) for Marcellus Shale time-series samples at well A, southwest Pennsylvania. The dashed line beginning with the sample on day 7 connects 226 Ra activities that are anomalously low relative to the overall 226 Ra activity trend. No corresponding anomaly appears in the 228 Raactivities or in the TDS values. The bestfit line and R 2 value shown for 226 Ra excludes the three anomalously low values and the final two points in the time-series which are interpreted as a plateau in 226 Ra activities (see text).

200 Geochemistry of Produced Water from Marcellus Shale Water, PA

### Marcellus Shale formation waters are distinctive due to their comparatively low 228 

### Ra ∕ 226 

### Ra values combined with geologically elevated 226 

### Ra activities generally ≥ 2000 pCi/L. These factors identify the water produced from the Marcellus Shale as derivedfrom the shale itself, rather than, for example, sandstones in the overlying Upper Devonian section. Samples from day 7 in the time-series at well A revealed an anomalously low 226 

### Ra activity of 3000 pCi/L (11,370 pCi/USgal), or about 2600 pCi/L (9854 pCi/USgal) below the line representing the longer term trend (Figure 9). After several subsequent samples, the 226 

### Ra activity returned to its previous trajectory (Figure 9; Rowan et al. 2011). The anomaly has been tentatively interpreted as a pocket of isotopically distinct water, but the anomaly is not distinguishable by TDS or most of the other majorelements (Figure 3; Table 1). The anomaly is interpreted as water from a lithologically distinct facies in the Marcellus Shale, intersected by fractures, and allowed to flow into the wellbore as the volume of shale being drained expanded. A facies containing less organic-rich shale, and greater fractions of sand and silt, for example, would be consistent with lower
226 

### Ra activity due to the lower U content of most clastic-rich rocks relative to organic-rich shales (Adams and Weaver, 1958). The radium isotope anomaly on day 7 was accompanied by a decrease in 87 

### Sr ∕ 86 

### Sr (Chapman et al., 2012), and by a spike in K concentrations from 309 to 1208 mg/L, then returning to 308 mg/L (Table 1). Following day 7, anomalously low 226 

### Ra activities and correspondingly high 228 

### Ra ∕ 226 

### Ra ratios were detected in the subsequent 2

– 3 samples over at least several weeks (Figure 9). The persistence of the anomaly indicates that the water produced during this period did not immediately acquire the isotopic ratio and 226 

### Ra values characteristic of the Marcellus Shale despite contact with it. Thus, if water werebeing drawn into the Marcellus Shale from an overlying or underlying reservoir, anomalous 228 

### Ra ∕ 226 

### Ra ratios and 226 

### Ra values should be detected in the samples, and should reflect their source. As such, radium activities and isotopic compositions appear to be a useful tool for detecting lithologic differencesbetween reservoirs, and the provenance of the produced water. Reservoir Properties and Imbibition

Using injected water volumes compiled from the Fracfocus.org website, and produced-water volume data from the IHS Inc. energy database, the followingestimates were made of minimum water recovery percentages relative to the injected volumes: well A, 48% (over 30 months), well B, 37% (over 18 months), andwell C, 18% (over six months). Some of the producedwater volume records appeared to be incomplete, and in at least two cases, did not appear to include the water produced during initial flowback, that is, within the first week of flow after hydraulic fracturing. With more complete information and monitoring over a longer time period the recovery percentages might eventually exceed the injected water volumes, at which point it would be clear from the volumes alone that natural formation water was flowing from the well. In the shorter term, if only a fraction of the injected water volume is recovered, and the water that is produced has been mixed with and largely replaced by much more saline and 18 

### O-enriched formation water, the question arises, what became of the water originally injected? Several authors have suggested that water is locked into the shale during hydraulic fracturing by the process of imbibition (Byrnes, 2011; Roychaudhuri et al., 2011; King, 2012b). During hydraulic fracturing, the pressure gradient between the water in the fractures, and the ambient reservoir pressure can cause a significant fraction of the injected water to be imbibed into small pores in the shale (Byrnes, 2011; Roychaudhuri et al., 2011). High fluid pressures at the fracture face can exceed the capillary entry pressures of a wide range of pore sizes, allowing fluid to enter them. As pressure in the reservoir declines, the imbibed water is unlikely to be released because similarly high pressures are required to expel the flui d from the pores (Byrnes, 2011; Roychaudhuri et al., 2011; King, 2012a). The imbibition process may continue over a period ofweeks to months at rates determined by reservoir permeability, water saturation, capillary pressures, and porosity (Byrnes, 2011). After hydraulic fracturing, the produced water is initially composed of the injected water remaining in the wellbore and in the open fractures near it. Removal of a large fraction of the injected water from circulation is likely to hasten

R OWAN ET AL

. 201

### the shift in chemistry of the water that is produced from injected water to that of formation water. The matrix porosity of the Marcellus Shale is reported to range from 0.5 to 5%, although small pore sizes with high capillary entry pressures, and matrix permeabilities in the nano- to micro-Darcy range greatly limit the mobility of water in these pores(Passey et al., 2010; Lee et al., 2011). However, studies of Marcellus Shale have documented lithologic variability within the formation (e.g., Lash and Engelder, 2011). In addition to matrix porosity, Lee et al. (2011) report natural fracture porosities in the range of 2% to 7%. Hydraulic fracturing with proppant can increasefracture conductivity between 1 and 7 orders of magnitude (Warpinski et al., 2008), and can liberate gas and water that had previously been immobile. The hydraulically induced fracture networks allow waterand gas to drain from a large volume of rock by interconnecting kerogen-rich horizons, small natural fractures, and previously isolated facies potentially containing silt or fine-grained sand (Passey et al.,2010). We hypothesize that the majority of the formation water produced over the long term (at least 12 months) resided in natural fractures and the moreporous facies within the Marcellus Shale, and its volume may be sufficient to account for the formation water produced from the Marcellus Shale.

SUMMARY

1. Analyses of produced-water samples from the Marcellus Shale indicate Na-Ca-Cl type brine with median TDS values of 158,000 mg/L in southwest PA, and 278,000 mg/L in north central PA. Na/Br and Cl/Br ratios of the water samples plot on or close to the seawater evaporation trend indicating that their salinity was derived predominantly from evaporatively concentrated seawater. The water produced from the Marcellus Shale over the long term (>1 yr) is interpreted to be paleoseawater, evaporatively concentrated past the onset of halite precipitation, subsequently modified by diagenesis, and mixed with a more dilute fluid. 2. The major element chemistry of these samples isbroadly similar to formation water from other reservoirs in the Appalachian basin, for example, sandstones of the Devonian and Silurian (Poth, 1962; Breen et al., 1985; Dresel and Rose, 2010). However, the concentrations and isotopic ratios of trace elements, such as Ra and Sr, are characteristic of water from the Marcellus Shale (Rowan et al., 2011; Chapman et al., 2012). The isotopic ratios 228 

### Ra ∕ 226 

### Ra, as well as 87 

### Sr ∕ 86 

### Sr (Chapman et al., 2012), do not support an external source, such as overlying or underlying reservoirs, for water produced from the Marcellus Shale. 3. In time-series samples of produced water, the δ 18 

### O values shift toward heavier values over time. Independent of the solutes and their source, the isotopic shift indicate s mixing between the injected water used for hydraulic fracturing, and indigenous water with distinctly heavier δ 18 

### O values. The plateau that is reached within approximately a year and the values measured in thegrab samples are interpreted as the oxygen isotopic composition of the natural formation water.4. The short time frame (days) of the initial, significant chemical changes in the time-series samples appears consistent with imbibition of the injected water into small pores in the shale. The imbibed water is considered effectively sequestered after the elevated pressures due to hydraulic fracturing decline (Byrnes, 2011). Imbibition may help to account for the low volume percentages of water recovered at the surface (commonly 5%

– 50%; King 2012a, b), relative to the volumes injectedduring hydraulic fracturing. Removal from circulation of a significant fraction of the injected water by imbibition should also speed the transition toward production of predominantly formation water.

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