Salinity reversal and water freshening in the Eagle Ford Shale, Texas

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Salinity reversal and water freshening in the Eagle Ford Shale, Texas, USA Jean-Philippe Nicot, Amin Gherabati, Roxana Darvari, and Patrick J. Mickler ACS Earth Space Chem., Just Accepted Manuscript • DOI: 10.1021/ acsearthspacechem.8b00095 • Publication Date (Web): 13 Sep 2018 Downloaded from http://pubs.acs.org on September 19, 2018

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ACS Earth and Space Chemistry

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Salinity reversal and water freshening in the Eagle Ford Shale, Texas, USA

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Jean-Philippe Nicot1*, Amin Gherabati1, Roxana Darvari1, and Patrick Mickler1

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Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin, Austin, Texas

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Corresponding author: Jean-Philippe Nicot ([email protected])

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Keywords: hydraulic fracturing, recycling, smectite, brackish water, unconventionals

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Abstract

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Effective, considerate shale play water management supports operations and protects the

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environment. A parameter often overlooked is total dissolved solids (TDS) of produced water

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from the formation. Knowledge of TDS is important to meet these dual goals. Subsurface TDS

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typically increases with depth. However, produced-water samples from the Eagle Ford Shale

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show a strong TDS decrease by a factor of ~10 with increasing well depth (~200,000 ppm at

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~2.5 km to 18,000 ppm at ~3.6 km). Water stable isotopes strongly suggest that the low TDS is

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not due to dilution by meteoric water. Rather, we attribute the change to smectite-to-illite

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conversion, in which the smectite interlayer water is released into the pore space. Depth,

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temperature, and other related indicators (source for K, excess silica) support such a mechanism.

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In addition, water-isotope patterns and 87Sr/86Sr ratios suggest a conversion operating with

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limited contributions external to the shale. Order-of-magnitude calculations show that the 8% of

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mixed-layer clay present on average in the Lower Eagle Ford Shale is sufficient to bring

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formation water TDS to observed levels when some of the resident water is expelled.

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Understanding that the low salinity is an intrinsic property of the formation water rather than due

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to short-term mixing allows stakeholders to have a more optimistic outlook on water recycling

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and on using produced water for other uses (irrigation, municipal).

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ACS Paragon Plus Environment

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1 Introduction

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Water management in unconventional plays using hydraulic fracturing1 (HF) has always been an

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operational challenge at several levels: (1) amount of water needed for completion; (2) limited

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capacity of disposal formations receiving produced waters (PW); and, more recently, (3)

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concerns about seismicity related to fluid disposal though injection wells. Recycling PW

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addresses these three “concerns” simultaneously. Amount of recycling is very variable across

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plays and operators but feasibility studies have been hampered by a lack of documentation on

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water quality, even on a parameter as simple as total dissolved solids (TDS). The Eagle Ford

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Shale (EFS) in South Texas is one of the major unconventional plays that have transformed the

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oil and gas production landscape in the U.S.. Of importance to this study, the source of the

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proppant-carrying water in the EFS play2-3 is not well documented but is generally reported as

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being fresh or brackish and extracted from local aquifers, mainly the Carrizo–Wilcox Aquifer.

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The current amount of recycling, which would change the nature of the HF water, is arguably

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low but is not known on a well-by-well basis.

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The geochemical characteristics of PW in shale plays are variable across plays and through time.

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They are a function of the added HF water and the resident formation water and can be further

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modified through rock–water interactions. Plays such as the Bakken and Marcellus exhibit high

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TDS up to 300,000 mg/L,4-5 whereas other plays such as the Fayetteville and EFS display TDS

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that can be much less (3 km). A

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common explanation for low TDS is the mixing of formation water with HF fresh water, which,

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however, is not supported by the characteristics of the EFS PW samples taken in the course of

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this study. We propose that the low TDS is a reflection of the natural system and a true

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representation of the formation water salinity.

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Researchers have documented that TDS, after a general increase, start decreasing with depth

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(>2.5–3 km) in Gulf Coast Basin shaly intervals and in clastic material in close spatial

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association with shales.6-13 Salinity, on the other hand, keeps increasing in higher-permeability

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sections.14 The mechanistic explanation of the salinity reversal is clay diagenesis, in particular,

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smectite-to-illite (S/I) conversion. Smectite clays contain bound water molecular layers regularly

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interspersed with Si and Al layers. These water layers become unstable at higher temperatures

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and pressures, releasing water from the interlayer space into the intergranular porosity.15-21

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In addition to acquiring knowledge of deep-flow systems in Upper Gulf Coast sediments in the

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vicinity of the EFS, this study has practical implications at several levels. Using accurate

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geochemical information about formation water is important because it impacts petrophysical

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interpretation of well logs. For example, knowing the TDS is critical for interpreting resistivity

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from which water saturations—and thus oil and gas saturations—can be calculated.22-24 Perhaps

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more importantly, natural low salinity also has operational implications; for example, water

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treatment of low-TDS water is less expensive and more amenable to recycling and other uses.

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The operational objective of our study was to understand PW chemistry and to investigate what

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was assumed to be mixing between formation water and HF carrier water. Examining natural

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tracers is the usual approach when investigating the potential mixing of waters from various

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sources. The EFS, which is enclosed within a sedimentary package that includes several low-

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permeability layers, is delimited for the purpose of this study by two relatively high-permeability

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intervals: the underlying Edwards Formation/Aquifer and the overlying Carrizo Formation and

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Wilcox Group/Aquifers (Figure S1). Little work has been published or accomplished toward

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understanding the nature of EFS formation water. However, a considerable amount of literature

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is available on the Edwards, Wilcox, and other Gulf Coast formations because of their

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importance as aquifers and as holders of large oil and gas conventional resources. Most

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information publicly available on EFS water quality derives from PW treatment studies and from

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anecdotal reporting of low TDS PW described in trade journals and in the gray literature (Table

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S6 and, e.g., Boschee et al.).25 A discussion of our S/I conversion conceptual model is presented

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in Section 4.1, including arguments to dismiss alternative explanations for the low TDS.

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2 Methods

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2.1 Site geology

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The general area of study, which covers ~20 Texas counties, extends from the Mexican border

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and Maverick Basin (Maverick and Webb Counties) to the generally accepted northern/eastern

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limit of the traditional EFS in Gonzales/Fayette Counties over the San Marcos Arch to Brazos

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County at the inception of the East Texas Basin (Eaglebine play). The EFS exhibits broad

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parallel zones of roughly equal size that display natural maturity gradation from oil to volatile oil

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to oil condensate, and to natural gas (Figure 1). The EFS is a major source rock for conventional

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hydrocarbon accumulations in the immediately underlying Buda Limestone and immediately

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overlying Austin Chalk.

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Figure 1. Location map showing sampled wells and oil, condensate, and gas windows22-23 which

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are color-coded by API gravity from ~30 (blue) in oil to ~65 (red) for dry gas.

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The EFS crops out occasionally in South and Central Texas, dips toward the Gulf of Mexico, and

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reaches depths >3.5 km.26 EFS mineralogical composition is >50% calcite with 10–20% clay

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minerals, half illite/smectite (I/S) mixed-layer clays. The EFS is included in a thick sedimentary

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package (Figure S1). Underlying formations of interest include, from oldest to youngest, the

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Edwards Limestone, the Del Rio Clay, and the Buda Limestone. The EFS is overlain by the

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Austin Chalk and the various mostly fine-grained siliciclastic formations capping the Cretaceous

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succession. The shaly Midway Formation marks the start of Cenozoic-age sediments. The thick,

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sometimes sandy Wilcox formations overlaid by the sandy Carrizo Formation complete the

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succession of interest. The Edwards and the Carrizo are two major aquifers that could interact or 5



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could have interacted with the EFS. The formations immediately underlying and overlying the

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EFS are low-permeability carbonates: the Buda Limestone and the highly fractured Austin

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Chalk. More geologic details are provided in Supporting Information Text C (SI-C).

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2.2 Sampling and analyses

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EFS wells were sampled for fluids (oil and water) in February–April 2017 (Figure 1). The

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samples were taken from oil wells operated by four different companies. Seven samples were

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provided to us, and we sampled 15 wells ourselves. Sampled wells reside mostly in the oil

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window and have been producing for a period ranging from a few months to a few years. We

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defined three geographic zones for convenience: an east zone (Gonzales, Karnes, and Atascosa

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Counties), with four samples located approximately along strike; a north zone (Lee and Brazos

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Counties) with three samples in the Eaglebine play; and a west zone (LaSalle, Atascosa, and Frio

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Counties), where most of the samples were taken, that approximatively represents an along-dip

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transect. See SI-A for sampling methodology and SI-B for laboratory analytical methods.

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2.3 Supplemental data

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In addition to collecting water samples, we made use of previously collected data and of existing

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databases (SI-D2). Gherabati et al.22-23 and Hammes et al.24 provide estimates of porosity, water

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saturation, temperature, and clay volume at the sampled well locations, interpolated in-house

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from contour maps created using petrophysical data of ~150 EFS wells with a comprehensive

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wireline log suite. Formation water content at sampled well locations was determined through

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the product of interpolated estimates of porosity and water saturation. We also used several

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public domain datasets : U.S. Geological Survey27 for PW geochemistry; FracFocus28 for

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information on stimulated oil wells; and Texas Water Development Board groundwater

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database29 (TWDB) for aquifer characteristics. The Enerdeq database has extensive information

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on oil wells but is available only from the private vendor IHS.30 6


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3 Results

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3.1 TDS and general geochemistry

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A generally accepted rule of thumb is that TDS increases with depth.6,13 The increase is generally

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attributed to rock–water interactions, mixing with deep brines or halite/salt dissolution. The

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study samples do not follow this general rule and show an extremely variable TDS, from a low

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of ~18,000 mg/L (west zone, well HI) to a high of >200,000 mg/L (east zone, well ST) (Figure

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2). TDS also increase with the amount of water produced (Figure S3b) and, to a lesser degree,

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with the PW volume as compared to the HF water volume (Figure S3c), possibly suggesting that

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low-TDS PW samples may result from mixing between formation water and HF water.

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However, the important observation of TDS consistently decreasing with increasing depth in all

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three sampling zones suggests otherwise. The highest TDS samples are found at the shallowest

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depth of ~2.4 km. TDS decreases almost linearly with increasing depth, a phenomenon

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particularly striking in the west zone, where samples are arranged along a dip-oriented transect.

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Temperature increases with depth (Figure S2a) and TDS is strongly correlated with bottomhole

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(BH) temperature (Figure S2b).

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The ionic makeup of the PW is dominated by Na and Cl (Table S4), with little sulfate and some

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Ca consistent with Gulf Coast formation waters. Little difference exists in ionic ratios between

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the high- and low-TDS samples (Figures S4 and S5). Na and Cl act conservatively, whereas Ca

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is relatively slightly higher in high-TDS samples, Mg is relatively depleted in high-TDS samples,

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and K is depleted in low-TDS samples. When normalized by Cl, it appears that Ca is

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progressively depleted relative to Na as the TDS decrease, possibly owing to calcite

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precipitation. Mg also sees a relative decrease with decreasing TDS, possibly following Ca,

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whereas K shows relatively high concentrations for some high-TDS samples.

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Figure 2. Produced water TDS as a function of well depth. Data in Table S4.

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3.2 Stable water isotopes

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The standard reference for water isotopes is seawater, which by convention is assigned δD and

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δ18O values of zero. Surface and shallow aquifer waters are almost always isotopically lighter

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than seawater, an outcome of the major source of rain—evaporation from seawater. In deep

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fresh-water aquifers, water isotopes typically represent climatic conditions when the aquifer was

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recharged. For example, the deeper downdip fresh-water sections of the Carrizo Aquifer in South

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Texas, which were recharged tens of thousands of years ago when the climate was much cooler,

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show water lighter than that in the recharge area.31-33 Figure 3a,b illustrates the common

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observation that formation waters have lighter hydrogen and heavier oxygen than shallow

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waters.13

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Water isotopes ranging from -23.1‰ to -14.9‰ and from +1.6‰ to +8.7‰ for δD and δ18O

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(Table S4), respectively, are consistent with values provided in the Clayton et al.34 seminal paper

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on formation-water isotopes and in Kharaka and Hanor.13 In addition, δD and δ18O increase

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together (0.5–1.5 δD ‰ unit for each δ18O ‰ unit). The lack of clear correlation between water

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isotopes and operational parameters, such as oil and water production and volume of HF water

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used, again suggests that mixing with HF carrier water has only a minor impact, if any, on the

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observed isotope relationships (Figure S6).

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Plotting water isotopes vs. depth (Figure 3c,d) offers a better correlation than vs. operational

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parameters and shows that, overall, water isotopes become heavier with increasing well depth.

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The plots also suggest that two trends are at play. The first trend shows heavier and heavier water

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isotopes as TDS increase as noted by the dot size, considering only samples originating from a

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depth of ~2.4 km, and could be related to residence time. The second trend, showing heavier

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water with increasing depth, is related to increasing temperature with increasing depth. At higher

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temperature, a smaller degree of fractionation of water isotopes with isotopically-heavy

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carbonates and clays drives water isotopes, particularly oxygen, to heavier values.

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(a)

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(b)


(c)

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(d)

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Figure 3. Water isotopes for produced-water samples and local aquifers (a) with focus on

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produced water (b). Water isotopes of formation water as a function of well depth: δ18O (c) and

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δD (d). GMWL = global meteoric water line. Bubble size is proportional to TDS on plots (b,c,d).

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Data in Table S4.

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Plotting water isotopes vs. BH temperature (Figure S7) rather than vs. well depth shows a more

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consistent pattern of TDS decreasing with increasing temperature. The pattern also suggests S/I

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conversion with limited contributions external to the shale. In such a semi-closed system, δ18O of

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clay should decrease with increasing temperature, as observed in the thick deposits of the Central

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Valley of California35 with a concomitant increase in the water δ18O, as observed here. The same

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Californian sequence also shows a whole-rock δD enrichment that would correspond to a

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decrease in the water δD consistent with our measurements, although obscured by a strong

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scatter. Gonzalez-Penagos et al.36 also observed an increase of pore water δ18O with depth in the

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Colombian shales they studied undergoing S/I conversion.

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3.3 Stable strontium isotopes

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Sr is found where Ca is found because both belong to the same column in the periodic table and

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Sr readily substitutes for Ca in common minerals. The ratio of two of the Sr natural isotopes

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(87Sr/86Sr) has proven useful in tracking rock–water interactions. It is usually accepted that ratios

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are the same (i.e., little fractionation) in water and rock.37 Typically, water will take the imprint

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of the Sr-bearing rocks in equilibrium with them, in particular carbonates. The 87Sr/86Sr ratio has

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varied through geologic times, with carbonate rock of each age carrying an almost unique

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signature (current value of 0.7092.38 Common complications arise when rocks are rich in K

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minerals (typically feldspars). Rb is a common substitute for K, as Sr is for Ca. 87Rb decays into

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87

Sr and increases the 87Sr/86Sr ratio through the Rb radiogenic contribution. Water exposed to

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K-bearing minerals will show an increased 87Sr/86Sr ratio. 87Sr/86Sr ratios of EFS waters are

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expected to be close to or higher than the seawater ratio at the time of deposition in the 0.7073–

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0.7075 range.39 Deviation from the original ratio occurs when mixing with unrelated water that

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carries a different 87Sr/86Sr ratio, e.g., more recent, or when the water is exposed to carbonates

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deposited in a different period, or when radiogenic Rb is present. The 87Sr/86Sr ratio of EFS

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samples has stayed close to the original ratio (Figure 4), especially for low-TDS samples,

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suggesting than no foreign waters have migrated into the EFS. A few higher-TDS samples show

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a higher ratio. A single sample in the east zone has a very high 87Sr/86Sr ratio value of 0.71045;

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its TDS is also the highest of all samples, at >200,000 mg/L.

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(a)

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Figure 4. 87Sr/86Sr isotope ratio as a function of (a) reciprocal Sr concentration, and (b) well

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depth. Bubble size is proportional to TDS. Range of seawater 87Sr/86Sr ratio during EFS

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deposition is shown by the small black box. Data in Table S4.

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4 Discussion

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In this section, we show that the S/I conversion model applies to the EFS. Alternative models for

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deep dilute formation waters can be hypothesized: (1) dilution of saline formation water by

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meteoric water; (2) dehydration of other minerals including kerogen; (3) cross-formational flow

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from overlying and/or underlying aquifers; (4) water condensation during sampling; (5) primary

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brackish; and (6) mixing with HF water. We present arguments in favor of S/I conversion,

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dismissing the other hypotheses.

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4.1 Full description of conceptual model

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Many elements point to an S/I conversion: (1) the conversion is common in Gulf Coast

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sediments and elsewhere; (2) conditions are met for the conversion to occur in Cretaceous

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formations; and (3) the system is mostly semi-closed (closed to inflows) and flow and transport

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are one-directional to the outside.

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(b)

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(1) S/I conversion common in Gulf Coast

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Clay diagenesis and water release have been observed in several formations of the Gulf Coast,6-7

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from older to younger formations: Eocene Wilcox,8-9 Oligocene Frio,10-11 and Miocene.12 In a

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more detailed study of the Frio Formation, Land and MacPherson10 identified a low-TDS “Na–

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acetate” water group (50% updip to 30% downdip. The average clay content (Vclay) is similar in

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both zones: 10–20% (east) and 8–18% (west). Properties interpolated at well locations (Figure

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S16) fall within the same range. In particular, calculated water content is consistent with the

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previous order-of-magnitude water content resulting from S/I conversion. The presence of

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hydrocarbons reduces the amount of water needed to achieve significant freshening of the

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formation water. However, the TDS reduction from the observed high values of >100 g/L to 2.5 km) within the EFS. The body of

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evidence strongly suggests that the low TDS is natural and not due to dilution of formation water

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by very low TDS HF carrier water. The most likely mechanism is the S/I conversion mechanism,

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common in the Gulf Coast, which releases enough water to dilute the resident formation water

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that has not been driven out of the EFS formation. The presence of hydrocarbons reduces the

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amount of water needed to achieve significant freshening of the formation water. Many

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unknowns remain. Petrographic evidence consistent with S/I conversion has not been described

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yet. The role of S/I conversion in the overpressurization of the EFS is unclear. More samples

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across a larger footprint of the play are needed to determine the extent of the conversion.

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Acknowledgments, Samples, and Data

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The paper is an outcome of a research project “Spatial Heterogeneity of Eagle Ford Crude”

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funded under research agreement EM10480/UTA16-000509 between ExxonMobil Research and

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Engineering Company and The University of Texas at Austin complemented by funds provided

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to the first author by The University of Texas at Austin Jackson School of Geosciences. We

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thank Tongwei Zhang, project Principal Investigator who helped in sampling the oil wells. We

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are also grateful to IHS to grant access to their oil and gas Enerdeq database. An earlier version

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of the work benefited from comments from BEG colleagues: Bridget Scanlon and Toti Larson,

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who also performed the water isotope analyses. Figure 1 was drafted by Francine Mastrangelo

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and Guin McDaid and the manuscript edited by Stephanie Jones.

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Supporting Information

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Sections A to F, Figures S1 to S16, and Tables S1 to S6 are provided in a single separate file.

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-

Analytical results and well characteristics: Sections A and B.

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Supplement on (hydro)geology: Section C

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Additional information on the conversion model: Section D

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Additional information on the alternative explanations: Section E

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Details on water budget calculations: Section F

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References

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Salinity reversal and water freshening in the Eagle Ford Shale, Texas

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