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 water

and solutes produced over the long term (>12 months). The question of whether the produced water originated within the

Marcellus Shale, or whether it may have been drawn from adjacent reservoirs via fractures is addressed using measurements of

228Ra∕226Ra and 226Ra 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 δ18O values were observed in the

produced water, followed by more gradual changes until a compositional plateau was reached within approximately 1 yr. The δ18O

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 provisional 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 paleoseawater. 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 Marcellus 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 total

natural gas reserves (272.5 tcf) and approximately 10% of the estimated technically recoverable gas 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 analyses 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 is

that 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 dissolving

halite, 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 δ18O 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.)

SystemOrdovician Silurian Devonian

Miss.

Penn.

Permian Cambrian

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 sh ton Gp

HamilHuntersville Chert

Chert

Eroded

Pottsdam 

Ss

Black River Ls

more ShNeedFigure 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).

ROWAN ET AL. 183
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 fact

have been drawn from overlying or underlying reservoirs via natural or induced fractures. Ratios of radiogenic isotopes such as 228Ra∕226Ra (this study) and

87Sr∕86Sr (Chapman et al., 2012; Capo et al., 2014)

address the question of the source reservoir of the

water by identifying specific, relatively narrow

ranges of values that characterize the water produced

from the Marcellus Shale.

The geochemical and isotopic data presented

here 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 10 100 

TDS (mg/L) 

(A) 

(B) 

(C) 

(D) 

Well A, time-series sample 

Well B, time-series sample 

Well C, time-series sample 

1 10 100 

Na (mg/L) 

1 10 100 

Cl (mg/L) 

0 1 10 100 1000 

Br (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 southwest

Pennsylvania. (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 well

B (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 have

made 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 target

horizon, the borehole is steered to a horizontal direction; the horizontal continuation is often called a

lateral. 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 pores

in 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 made

possible 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 pores

by 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 drained from the system

(King, 2012b). The greatest flux of water to the

surface occurs during the first few weeks of flow

from the well, but decreases rapidly as gas production increases. The water produced from the wells

includes 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 freshwater 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 the

Marcellus 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

ROWAN ET AL. 185
evaporative conditions prevailed, possibly including

the Permian.

Paleogeographic reconstructions indicate that the

Appalachian 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 the

major 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 authors

to 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 SO4 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 the

modern composition of seawater for purposes of discussion. We assume that the 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 limits

are 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 LiðbrineÞ∕molality of LiðseawaterÞ. At a DE

of ∼13, for example, precipitation of calcium carbonate and gypsum has depleted Ca from modern seawater, and halite has reached saturation (McCaffrey

et 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 (McCaffrey 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 and

Carpenter, 1986; McCaffrey et al., 1987). An average Br/Cl distribution coefficient of 0.032 for halite

was determined by McCaffrey et al. (1987). Brines

formed 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 the

same 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 possible

external sources of Br and found no viable alternatives to seawater evaporation. Similar arguments

would apply also to brines in the Devonian reservoirs

if their formation waters had a common origin. It is

also 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, 18O and 2H, are progressively

concentrated in the residual brine. Sofer and Gat

(1975), for example, reported a δ18O value of

+6.59‰ for bottom water in the Dead Sea, compared

with a δ18O value of zero in standard mean ocean

water (SMOW). Enrichment in 18O and 2H relative

to 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 LiðbrineÞ∕molality of LiðseawaterÞ (McCaffrey

et al., 1987). Evaporation data are from a study

of modern seawater by McCaffrey et al. (1987).

ROWAN ET AL. 187
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 δ2H

and δ18O 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 18O and 2H relative to SMOW (Sofer and Gat,

1975; Moldovanyi and Walter 1992).

PREVIOUS STUDIES

Commercial exploitation of Appalachian basin brines

for 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 

350 

Cl/Br (mg/L) Cl/Br (mg/L) 

30 40 50 60 70 80 

0 20 40 60 80 100 120 140 160 180 200 

Figure 5. Na/Br versus Cl/Br for

produced-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 of

the 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). Several

authors 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 geologic

questions, 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 investigation of Marcellus

Shale water samples, Blauch et al. (2009) reported

major element chemistry (Na, Ca, Mg, K, Cl, SO4,

and alkalinity) in addition to Ba, Sr, and Fe for produced water from two Marcellus Shale wells in

western and northeastern Pennsylvania, as well as

from 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 the

initiation of production. Little geologic or geochemical interpretation accompanied the data; however,

several aspects of the geochemistry of this study were

discussed 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 the

similarities 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 of

the 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 87Sr∕86Sr values of 0.7101 to 0.7121 characterize

their Marcellus Shale water samples, whereas samples from Upper Devonian sandstones have markedly

higher 87Sr∕86Sr 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 of

about 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

ROWAN ET AL. 189
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 all

eight 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. Grab

samples 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 from

both 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 the

storage tanks was homogeneous, and that its chemistry did not differ significantly 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 μm (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

BaðRaÞSO4 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 HCO3. The remaining

anion concentrations were determined by ion

190 Geochemistry of Produced Water from Marcellus Shale Water, PA
Table 1. Chemical Analyses of Produced-Water Samples*

Approx.

Reservoir

Depth, ft

(km)

Na K B Li Mg Mn Fe Ba Ca Sr Br I Cl SO4 HCO3 Co Cs Cu Ni Rb Pb Zn TDS

(Calc.)

mg/L μg/L

SampleNo. Sample Point Day Reservoir

ICPOES ICP- OES ICP- MS ICP- MS ICP- OES ICP- OES ICP- OES ICP- OES ICP- OES ICP- OES IC ICP- MS IC IC TITR ICP- MS ICP- MS ICP- MS ICP- MS ICP- MS ICP- MS ICP- MS mg/L

WELL A, GREENE COUNTY, SOUTHWEST PENNSYLVANIA

A-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 <1 758 167,000

A-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 <10 960 163,000

A-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 1,100 163,000

A-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 <10 990 169,000

WELL B, GREENE COUNTY, SOUTHWEST PENNSYLVANIA

B-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 25,900

B-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 28,500

B-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 71,400

B-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 78,800

B-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 83,400

B-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 86,400

B-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 93,200

B-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 99,800

B-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 2,110 125,000

B-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 1,040 155,000

B-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 <10 910 152,000

B-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 <10 970 161,000

WELL C, GREENE COUNTY, SOUTHWEST PENNSYLVANIA

C-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 42,600

C-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 )

ROWAN ET AL. 191
Table 1. Continued

Approx.

Reservoir

Depth, ft

(km)

Na K B Li Mg Mn Fe Ba Ca Sr Br I Cl SO4 HCO3 Co Cs Cu Ni Rb Pb Zn TDS

(Calc.)

mg/L μg/L

SampleNo. Sample Point Day Reservoir

ICPOES ICP- OES ICP- MS ICP- MS ICP- OES ICP- OES ICP- OES ICP- OES ICP- OES ICP- OES IC ICP- MS IC IC TITR ICP- MS ICP- MS ICP- MS ICP- MS ICP- MS ICP- MS ICP- MS mg/L

C-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 57,000

C-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 60,900

C-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 62,500

C-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 75,900

C-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 87,300

C-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 92,500

C-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 96,300

C-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 102,000

C-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 106,000

C-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 107,000

C-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 137,000

C-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 148,000

C-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 2,000 154,000

WELL D, GREENE COUNTY, SOUTHWEST PENNSYLVANIA

D-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 <10 800 149,000

D-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 <10 710 153,000

WELLS IN TIOGA & LYCOMING COUNTIES, NORTH CENTRAL PENNSYLVANIA

NE81 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 280,000

CU82 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 276,000

MA28 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 274,000

SA14 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 316,000

CO12 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 258,000

NE13 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 301,000

ST46A 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 284,000

ST46B1 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 201,000

ST46B2 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 184,000

FO72 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 272,000

YO48 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 302,000

PA50 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 289,000

SH23 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 222,000

WELLS PRODUCING FROM UPPER DEVONIAN SANDSTONES, GREENE COUNTY, SOUTHWEST PENNSYLVANIA

GO2_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 <200 175,000

GO2_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 <200 188,000

MC1_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 <100 156,000

MO5_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 <10 260 162,000

MO5_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 <100 154,000

PR3_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, SO4

measurements were below the analytical detection

limits (0.03–225 mg/L). The detection limits varied

between samples and laboratories due to the low initial SO4 concentrations in the 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 μm (1.8 × 10−6 in.) filter and dissolve in an acidified sample. Ideally, a

0.1 μm (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 Isotopes

Laboratory, in Reston, Virginia. A hydrogen equilibration method was used to determine δ2H, and

δ18O was determined by CO2 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 18O and 2H increase

with increasing salinity. The corrections were made

to allow comparison of our data with previously published isotope data, much of which was determined

by analytical methods that yield concentrations

directly. Table 2 shows both the activities (uncorrected) and the concentrations (corrected); only the

concentrations were used in plotting figures. The isotopic data are reported in per mil notation relative to

Vienna standard mean ocean water (VSMOW) standard; one standard deviation of measurement uncertainty is equal to 0.1‰ for δ18O and 1‰ for δ2H

(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 injected

fluid 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 to

the 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 such

as 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

ROWAN ET AL. 193
Table 2. Activity and Concentration Values of δ18O and δ2H for Produced-Water Samples

δ2H (‰) δ18O (‰) δ2H (‰) δ18O (‰)

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 stabilizes

in 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 SO4 and

HCO3 (Table 1). The median SO4 concentration of

the 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

δ2H (‰) δ18O (‰) δ2H (‰) δ18O (‰)

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

ROWAN ET AL. 195
SO4 source was the water used for hydraulic fracturing. King (2012b, his figure 1) indicates that declining

SO4 concentrations in the water produced immediately after hydraulic fracturing can be used to track

the fraction of injected fluid in the water. Dresel and

Rose (2010) provided evidence of reducing conditions that imply very low SO4 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 anticipate

similarly reducing conditions. The high Ba concentrations ultimately measured in the produced water from

the Marcellus Shale (103 to 104 mg∕L) also imply

very low natural concentrations of dissolved SO4 in

the reservoir due to the low solubility of barite

(Ksp ∼ 10−10; Monnin, 1999).

A limited number of measurements of HCO3

were made in the time-series samples from wells A

and B. However, HCO3 analyses are not available

for the injected water. The general decrease in HCO3

concentration from 364 to <100 mg∕L in the timeseries suggests that its primary source, like SO4, was

from the water injected for hydraulic fracturing.

Similar observations of declining HCO3 and SO4

were reported by Blauch et al. (2009) in analyses of

time-series samples, and Dresel and Rose (2010)

reported low HCO3 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,

SO4, and HCO3 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 SO4 (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 seawater, all of our produced-water samples are enriched in Ca and depleted

in Mg (Figure 4; Table 1). This pattern is consistent

with basinal brines derived from evaporatively concentrated seawater that have been modified by commonly occurring diagenetic reactions (Carpenter,

1978; Sanders, 1991; Dresel and Rose, 2010). The

recrystallization 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 north

central PA (Figure 4). Both regions have similar fractions of Mg, but the equivalent fractions of ðNa +

KÞ∕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 depletion

through 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 reduce

Br to below the concentrations measured in the samples. For southwest PA, we therefore investigated

the amount of dilution needed at several points farther

along 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%, based

on 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

δ18O and δ2H 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, the

resulting 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 interconnected

basins 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 later

underwent differing degrees of dilution and diagenetic modification.

Oxygen and Hydrogen Isotopes

The δ18O and δ2H 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 δ18O values of both regions overlap, but

the median in north central PA (−1.4‰) is more

enriched in 18O 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 δ18O 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 δ18O values shifted from the

injected water value of −3.8 to −2.5‰, but the δ2H

values were unchanged (Figure 7; Table 2). The magnitude of the shifts in δ18O decreased over time until

reaching a plateau at about −1.85 ± 0.2‰. At well

B, the δ18O 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 closely

associated 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

ROWAN 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 δ18O 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 δ18O 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 δ18O 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 

δ

18O, H2O (‰, VSMOW)

2H, 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 

Figure 6. δ18O versus δ2H for -20 

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 1,000 

18O, H2O (‰, VSMOW)

Time (days) 

Well A, injected water 

Well C, time-series 

Well B, injected water 

Well B, time-series

Well D

δ

Well A, time-series

-6 

-5 

-4 

-3 

-2 

Figure 7. δ -1 18O 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 stages

of 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‰ δ18O.

198 Geochemistry of Produced Water from Marcellus Shale Water, PA
had converged on δ18O values between approximately −1 and −2‰.

The δ2H 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 δ2H and TDS, might

be explained by hydraulic fracturing with water

recycled from the Marcellus Shale and Upper

Devonian sandstone gas wells, both with δ2H values

of −40 ± 5‰, and diluted by local meteoric water

whose δ2H range overlaps that of the produced water

samples. This explanation is consistent with Dresel

and Rose (2010) who reported that the δ2H values

of their samples were, with one exception, consistently in the −40 ± 5‰ range despite originating

from different formations.

Although strongly positive δ18O and δ2H 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 δ2H values in virtually all of our

samples are in the −40 ± 5‰ range, whereas the

heaviest δ18O value measured in this study is

−0.52‰. Therefore, dilution or mixing does not

appear to be required to account for the δ18O and

the δ2H 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 occur

on 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 δ18O values related to rock–water interaction. Rather, the 18O enriched water is interpreted

to be formation water released from the Marcellus

Shale.

In the time-series samples in southwest PA, δ18O

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 δ18O is

consistent with imbibition of a significant fraction of

the injected water, effectively removing it from circulation. Subsequent, more gradual shifts in δ18O 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. δ18O versus TDS for

Marcellus Shale samples. Southwest

Pennsylvania (PA): time-series samples

of produced water from wells A–C and

grab 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.

ROWAN 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 fluid

whose salinity originated predominantly from evaporated seawater.

The TDS and δ18O 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-δ18O correlation is related

to 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 of

mixing 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, are

tightly clustered in comparison with the grab samples from north central PA, consistent with the

closer spacing of the wells from southwest PA

within 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 δ18O

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, 226Ra activity

reaches a plateau at approximately 9500 pCi/L after

about 12 months of production (Figure 9). The

228Ra∕226Ra ratio in the produced water reflects the

abundances of their respective parent isotopes,

232Th and 238U, 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 228Ra∕226Ra 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 228Ra∕226Ra ratios of 1 to 1.6

(Vengosh et al., 2009). Based on the limited data

available for the Appalachian basin, the median

228Ra∕226Ra 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 1,000 

Activity (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 

175,000 

TDS (mg/L) 

Produced water 

TDS, Well A (right axis)

Injected water

Injected water

Figure 9. Total dissolved solids

(TDS), 226Ra, and 228Ra 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 226Ra activities that

are anomalously low relative to the

overall 226Ra activity trend. No corresponding anomaly appears in the 228Ra

activities or in the TDS values. The bestfit line and R2 value shown for 226Ra

excludes the three anomalously low

values and the final two points in the

time-series which are interpreted as a

plateau in 226Ra activities (see text).

200 Geochemistry of Produced Water from Marcellus Shale Water, PA
Marcellus Shale formation waters are distinctive

due to their comparatively low 228Ra∕226Ra values

combined with geologically elevated 226Ra activities

generally ≥2000 pCi/L. These factors identify the

water produced from the Marcellus Shale as derived

from 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 226Ra 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 226Ra 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 major

elements (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

226Ra 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 87Sr∕86Sr (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 226Ra activities and correspondingly high 228Ra∕226Ra 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 226Ra values characteristic of the Marcellus

Shale despite contact with it. Thus, if water were

being drawn into the Marcellus Shale from an overlying or underlying reservoir, anomalous 228Ra∕226Ra

ratios and 226Ra 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 differences

between 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 following

estimates were made of minimum water recovery percentages relative to the injected volumes: well A, 48%

(over 30 months), well B, 37% (over 18 months), and

well 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 18O-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 fluid from the pores (Byrnes,

2011; Roychaudhuri et al., 2011; King, 2012a). The

imbibition process may continue over a period of

weeks 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

ROWAN 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 increase

fracture 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 water

and 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 more

porous 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 is

broadly 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 228Ra∕226Ra, as well as 87Sr∕86Sr

(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 δ18O

values shift toward heavier values over time.

Independent of the solutes and their source, the

isotopic shift indicates mixing between the

injected water used for hydraulic fracturing, and

indigenous water with distinctly heavier δ18O values. The plateau that is reached within approximately a year and the values measured in the

grab 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 injected

during 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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