Chemical Degradation of Polyacrylamide during Hydraulic Fracturing

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Chemical Degradation of Polyacrylamide during Hydraulic Fracturing Boya Xiong, Zachary Miller, Selina Roman-White, Travis L Tasker, Benjamin Farina, Bethany Piechowicz, Prachi Joshi, Liang Zhu, Christopher A. Gorski, William D Burgos, Andrew L. Zydney, and Manish Kumar Environ. Sci. Technol., Just Accepted Manuscript • DOI: 10.1021/acs.est.7b00792 • Publication Date (Web): 27 Nov 2017 Downloaded from http://pubs.acs.org on December 5, 2017

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Environmental Science & Technology

This study evaluates the chemical degradation of high molecular weight polyacrylamide used widely as fraction reducer in the hydraulic fracturing process. 45x25mm (300 x 300 DPI)

ACS Paragon Plus Environment


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1

Chemical

Degradation

of

Polyacrylamide

during

Hydraulic

Fracturing Boya Xiong†, Zachary Miller‡, Selina Roman-White‡, Travis Tasker†, Benjamin Farina‡, Bethany Piechowicz‡, William D. Burgos†, Prachi Joshi†, Liang Zhu§, Christopher A. Gorski†, Andrew L. Zydney*‡, Manish Kumar*†‡

†Department of Civil and Environmental Engineering, ‡Department of Chemical Engineering, § Department of Material Science and Engineering, The Pennsylvania State University, University Park, Pennsylvania 16802, United States

ABSTRACT Polyacrylamide (PAM) based friction reducers are a primary ingredient of slickwater hydraulic fracturing fluids. Little is known regarding the fate of these polymers under downhole conditions, which could have important environmental impacts including strategies for reuse or treatment of flowback water. The objective of this study was to evaluate the chemical degradation of high molecular weight PAM, including the effects of shale, oxygen, temperature, pressure, and salinity. Data were obtained with a slickwater fracturing fluid exposed to both a shale sample collected from a Marcellus shale outcrop and to Marcellus core samples at high pressures/temperatures (HPT) simulating downhole conditions. Based on size exclusion chromatography analyses, the peak molecular weight of the PAM was reduced by two orders of magnitude, from roughly 10 MDa to 200 kDa under typical HPT fracturing conditions. The rate of degradation was independent of pressure and salinity but increased significantly at high temperatures and in the presence of oxygen dissolved in fracturing fluid. Results were consistent with a free radical chain scission mechanism, supported by measurements of sub-μM hydroxyl radical concentrations. The shale sample adsorbed some PAM (~30%), but importantly it catalyzed the chemical degradation of PAM, likely due to dissolution of Fe2+ at low pH. These results provide the first evidence of radical-induced degradation of PAM under HPT hydraulic fracturing conditions without additional oxidative breaker.


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Environmental Science & Technology 2

INTRODUCTION The environmental impact of high-density high volume hydraulic fracturing (HVHF) operations for unconventional natural gas processing has raised tremendous concerns from the public. These concerns are significant due to the large quantity of water required for HVHF and the challenges associated with managing the resulting wastewater1-3, which contains high salinity (up to 340,000 mg/L), turbidity, organic carbon (1-5,800 mg/L) and radioactivity (gross alpha of 50-120,000 pCi/L)4, 5. In addition, fluids used for HVHF contain a large variety of organic chemicals6 (996 distinct organic compounds7 according to the U.S. Environmental Protection Agency). Many of these chemicals are mixtures whose ingredients are listed as “proprietary”

additives8. These man-made chemical mixtures are the dominant organic species present in the early flowback water produced in the first few days to weeks of well stimulation, with total organic carbon (TOC) as high as 5500 mg/L in the Marcellus play. The TOC of produced water generated later (throughout the life time of a well) decreases to an average of ~ 40 mg/L, with hydrocarbons from the formation becoming the dominant organic species4. Recent efforts have begun to identify the complexity of the organic species present in HVHF produced waters by utilizing liquid chromatography9-12, as well as one-4, 13 and two-dimensional gas chromatography14-17, often coupled with time-offlight mass spectroscopy. These efforts have identified surfactants4, 4

4

9, 13

glycol , phthalate esters , and acetic acid 10-13

10, 17

, ethylene

among many others in both flowback4, 5,

and impacted surface waters15 and groundwater14, 17. However, current analyses

have focused on small and volatile molecules. Components with molecular weights (MWs) larger than 1 kDa, such as guar gum (used as a gelling agent) and polyacrylamide (PAM) (used as a friction reducer), have remained largely uncharacterized in flowback waters as they are not detected using current techniques15. Our review of 100 randomly selected fracturing jobs in Pennsylvania from 2015 to present found that polyacrylamide was used in 100% of the fracturing jobs (slickwater fracturing). For example, this type of fracturing fluid can contain 0.15% v/v friction reducer while the sum of the other organic additives contributes less than 0.1% v/v including surfactants, biocide, iron control and corrosion inhibitors8. These polymers can potentially: 1) reduce the effectiveness of wastewater treatment processes including membrane filtration18,

19


, biological removal20,

21

,


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3

adsorption-based processes22, and electrocoagulation23; 2) damage formations leading to reduced permeability24,

25

and thus well productivity; and 3) release potentially

toxic monomers, for example acrylamide from PAM26. There is some work on the degradation of guar and its derivatives, showing that raw guar (2-4 MDa MW27) can be degraded via hydrolysis and backbone chain scission28 upon the addition of enzymatic breakers29, acids30, persulfate and peroxide breakers31, and in the presence of microorganisms21. In contrast, the degradation mechanisms of PAM under high pressure and temperature (HPT) similar to downhole conditions have yet to be examined. Slickwater HVHF uses a low concentration (0.002-0.07% w/v, 0.6-22 ton/well8) of linear PAM as a drag reducer to minimize friction along the flow line32. Typical commercial PAM used as a friction reducer (FR) has a molecular weight ranging from 1-25 MDa. PAM can be nonionic (i.e. acrylamide as the single monomer), anionic (i.e. with acrylic acid as co-monomer) or cationic (i.e. with dimethyldiallylammonium chloride and butylacrylate as co-monomers33). PAM, in other contexts, has been shown to be susceptible to biological, thermal, mechanical and photo-induced degradation34-36. Oxidative breakers, such as persulfate, are commonly added in mixed fracturing fluids containing both gelling agent and friction reducer, to break down polymer and enhance flowback recovery37,

38

. Only 20% of fracturing jobs

utilize such mixed fluids containing both a gelling agent and a breaker8, thus the scenario of PAM alone is the most environmentally relevant and is the focus of this study. Pulse radiolysis of PAM has been shown to cause chain scission in an oxygen saturated aqueous environment; in contrast, crosslinking of PAM was observed in the absence of oxygen based on time-resolved light scattering measurements39. PAM degradation is thought to occur via a bimolecular reaction with the rate determining step shown in equations (3) and (4) following the attack of polymer by HO (1) and formation of peroxyl radical (2). PH + HO ⟶ P + H O

(1)

P + O ⟶ PO

(2)

which can then lead to chain scission43 2PO ⟶ POOOOP ⟶ 2PO + O

(3)

PO ⟶ F + F

(4)


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where F1, F2, F3 and F4 are polymer fragments. A few studies have correlated the reduction in PAM viscosity with the concentration of dissolved oxygen, ferrous iron (Fe2+) at mg/L levels, and elevated temperatures40, 41 in other contexts. However, there have been no studies of the detailed molecular mechanism of PAM degradation at high pressure, temperature, and salinity in the absence of any added oxidative breaker. Deep shale environments can be highly variable and formation dependent. Reservoir temperature depends strongly on formation depth. The temperature in Marcellus Shale formations (1200 to 2600 m) is in the range of 40-100 ℃, with typical pressures ranging from 270 – 410 bar42 but in some cases conditions could be more extreme. As an example, Haynesville shale in the southern United States is a deeper formation with temperatures and pressures reaching as high as 200℃ and 700 bar43, respectively. Deep formations also have an extremely high salinity, with total dissolved solids (including high level of hardness) reaching as high as 300,000 mg/L5. In this study, we examined the role of HVHF relevant conditions including temperature, pressure, the presence of shale and high salinity in the chemical degradation of PAM. We simulated high pressure fracturing conditions using a Parr reactor with a recently validated procedure44, and carefully examined the change in molecular weight distribution of PAM in a commercial FR formulation using conventional size exclusion chromatography (SEC). The results are shown to be consistent with the free radical degradation mechanism (in the absence of breaker), including important roles of dissolved oxygen, superoxide and hydroxyl radicals, and the presence of Fe2+ on PAM degradation under HVHF relevant conditions.

MATERIALS AND METHODS Friction reducer and shale characterization. Friction reducer (FR) stock was obtained from Weatherford International Inc. and is identical to what is used in actual hydraulic fracturing operations. The stock was a highly viscous and cream-colored fluid (Fig. 1A). The Material Safety Data Sheet provided by the supplier indicates that the product contains 20-40% petroleum distillates (CAS# 64742-47-8), with no information given on the characteristics of the PAM. Previous analyses by Gas Chromatography coupled with a Flame Ionization Detector indicated that the organic phase contained a high proportion of C10-C14 hydrocarbons44. To quantify the high molecular weight (polymer) fraction in the FR stock, we estimated bulk mass fraction



of volatile and non-volatile fraction based on the residue mass after overnight evaporation under vacuum. Additional analyses of FR stock were conducted using Thermo Gravimetric Analyses (TGA) with methods described in SI. Slickwater fracturing fluid was formulated by blending 1.5 ml FR stock (original and unfractionated) with 1 L deionized water obtained from a Barnstead Nanopure water purification system with a resistivity of >18 MΩ∙cm. An image of the fracturing fluid is presented in Fig. 1A. The concentration of FR used in this study was based on a previous study44 and a careful examination of drilling logs provided by FracFocus.Org44, 45. The mixtures were blended for 30 s and the pH was then adjusted to 7.2 using 1 M potassium hydroxide or 1 N sulfuric acid as needed. Marcellus Shale was collected from a shale outcrop near Frankstown, PA; it had a 6 meter overburden and had been exposed to the atmosphere. We first removed 0.5 cm of the outer oxidative layer of the shale sample; only the inner part was used for this study. The shale sample was then pulverized by first applying load using polycarbonate plats and then grinding with mortar and pestle to a sieve size of 0.3-2 mm (picture shown in Fig. SI-1A, right). The pulverized shale had high surface area for interaction with the PAM and was thus more representative of the high surface area fractures in downhole formations after fracking. The pulverized shale sample was stored in a sealed container at room temperature until use in the experiments. Pore size analysis based on N2 adsorption/desorption data using the Barret, Joyner and Halenda (BJH) model suggests that the shale is mesoporous with a dominant pore size of 40 nm (Fig. SI-2). The mass fractions of structural water, hydrocarbon, and carbonate minerals were estimated using TGA. The mineralogy and elemental composition of the shale was characterized by X-ray diffraction (XRD) (Fig. SI-3) and scanning electron microscopy coupled with energy dispersive spectroscopy (SEM-EDS, Table SI-1); details are provided in the SI. Additional composition information based on sequential extraction can be found in a previous study44. Limited experiments were also performed using two Marcellus shale core samples obtained from repositories at the Pennsylvania Geological Survey. The core samples contained different amounts of pyrite and calcite, with compositions that are representative of gas shale samples46. Mineralogy of the core samples, determined by XRD and sequential extraction analyses, are provided in a previous study44. Simulated fracturing reaction.

Synthetic flowback water was created by

exposing the slickwater HVHF fluid to shale at temperatures and pressures similar to ACS Paragon Plus Environment

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those encountered downhole during HVHF operations44. An image of an example synthetic flowback water with shale removed by centrifugation after incubation is presented in Fig. 1A. For pressurized incubations, 5 g of pulverized shale was first mixed with 200 ml of freshly prepared fracturing fluid in a 500 ml stainless steel Parr reactor (Model 4575, Parr Instrument Company, Moline, IL) with a pressure limit of 345 bar. The reactor had a PTFE liner that fully covered the stainless steel. Control experiments conducted in the absence of any added polymer confirmed that there was no measureable polymer release from the reactor after 24 h incubation at 83 bar and 80 ℃ in the presence of 25 g/L shale and 3 M NaCl. Temperature was ramped up to the desired value within 30 minutes followed by pressurization with nitrogen gas, with the pressure monitored using a digital pressure transducer (Model 4848 reactor controller for both temperature and pressure control). A photograph of the reactor is shown in Fig. SI-1B. The fracturing fluid was incubated with the shale for specified periods of time. The resulting suspension was then removed from the reactor and centrifuged at 13,700 g for 1 h at 4℃ to remove the shale debris, and the supernatant was collected as “synthetic flowback water”. The centrifugation caused no loss of high MW polymer in the synthetic fracturing fluid. Experiments at atmospheric pressure were performed by mixing 16.5 ml of fracturing fluid with 0.42 g of shale in a 27 ml sealed glass serum bottle with a PTFE rubber septum and aluminum cap. Temperature was controlled by a digital water bath. Each bottle was sacrificed for sample collection at designated times; samples were drawn using a needle syringe followed by immediate filtration through 0.45 μm cellulose acetate syringe filters (without centrifugation).

In order to elucidate the effect of Fe2+ on polymer

degradation, control reactions were conducted without the use of shale but with the addition of 280 mg/L FeSO4 stock (in 0.5 M HCl) to reach a desired Fe2+ concentration and pH. The synthetic fracturing fluids used for high salinity experiments were prepared by blending FR stock in 3 M NaCl or 1.5 M CaCl2 solution followed by reaction with shale within 1 h. A majority of the experiments were conducted under aerobic conditions, in which raw fluid contained ambient level of dissolved O2 (equilibrated with air), 35% air headspace and shale sample that was not treated with vacuum. Anoxic conditions were achieved by first incubating the shale under vacuum for a minimum of 12 h and by purging all fluids with nitrogen gas for 5 h. The resulting



suspensions were mixed and sealed in serum bottles inside of an anaerobic chamber. Unless specified, the O2 condition for each reaction is referred as either aerobic or anoxic condition described above. Hydroxyl radical detection. Terephthalate (THA) (Sigma Aldrich, MO) was used as probe for trapping hydroxyl radicals. The reaction product, hydroxylated terephthalate, is a fluorescent molecule with 310 nm excitation wavelength and 425 nm emission wavelength47, 48, which was measured using a SpectraMax i3x MultiMode microplate reader. Terephthalate with a concentration of 2 mM was added to the reaction mixture, with the hydroxyl radical concentration calculated using the calibration curve constructed with hydroxylated terephthalate from 0.01-1 μM (Sigma Aldrich, MO). Experiments were also performed using tert-butanol (Sigma Aldrich, MO) as a generic radical scavenger. Flowback characterization. Total organic carbon (TOC) was evaluated using a Shimadzu TOC-VCPH analyzer with non-purgeable organic carbon. Each sample was unfiltered and diluted 5-20 times with DI water to ensure operation in the linear portion of the calibration curve. The molecular weight (MW) distribution of polymer in these samples was evaluated by conventional size exclusion chromatography (SEC) using a Shodex SB-806M HQ aqueous SEC column with maximum exclusion limit of 20 MDa. The SEC column was connected to a Waters HPLC system with 1515 pump and 2414 refractive index detector. All samples were pre-filtered through 0.45 μm cellulose acetate syringe filters before injection into the column. Analyses were conducted using 0.05 M Na2SO4 as the mobile phase at a flow rate of 0.5 ml/min with 100 μ l injection volume. Nonionic PAM standards (American Polymer Standard Corporation, Mentor, OH) with four different molecular weights at a concentration of 0.05% w/v were used for calibration. The elution volumes of the polymer standards were highly reproducible; an example chromatograph is presented in Fig. SI-4A. The calibration curve was constructed from the measured elution volume at peak position as a function of the peak MW provided by the manufacturer (Fig. SI-4B). Polymer concentrations were estimated by integration of the peak area in the SEC chromatograph using a calibration curve constructed with the polymer standards over a range of molecular weights (Fig. SI-5). The concentrations of total dissolved iron and Fe2+ were measured using 1,10phenanthroline49 with ferrous ammonium sulfate stock solutions (1-200 μ M) as


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standards. Dissolved oxygen in fracturing fluid and flowback was measured using Mettler Toledo® InLab OptiOx dissolved O2 probe. The estimation of total oxygen in the reactor before and after reaction is described in SI. Ammonia concentration was measured using Hach® Nitrogen-Ammonia reagent set (product # 2606945); the release of ammonia provided information on the extent of PAM hydrolysis. X-ray photoelectron spectroscopy (XPS) and Attenuated total reflectance-Fourier transform infrared spectroscopy (ATR-FTIR) with a diamond crystal were used to characterize the chemical composition of PAM in FR stock and in flowback. FR stock and flowback was vacuum dried for 24 h into powder for analyses. Details regarding XPS and ATR-FTIR analyses are described in SI.

RESULTS AND DISCUSSION Molecular size reduction and adsorption of FR polymer under downhole conditions The exposure of synthetic slickwater fracturing fluid to shale for 24 h under typical HVHF conditions resulted in 70% TOC loss from 230 to 70 mg/L (Table 1) and a nearly two orders of magnitude reduction in size of the polymer (Fig. 1B). SEC analysis of the (raw) synthetic fracturing fluid showed a peak MW of approximately 10 MDa, corresponding to an effective hydrodynamic radius (Rh) of 350 nm. The refractive index profile for the fluid after HPT reaction with shale was significantly shifted to higher elution volumes (black solid to red dot), corresponding to a large reduction in the peak MW down to 200 kDa (Rh=80 nm). Also shown for comparison is the SEC profile of a 6,500 kDa PAM standard; the raw fracturing fluid has a slightly larger peak elution volume than the standard. PAM contributes to 6% mass of the FR stock according to TGA analysis. The TGA analysis indicated that the FR stock contains 77% small organics, in which 60% is light hydrocarbon that can be volatilized during overnight vacuum incubation; the remaining mass (17%) is surfactants (Table SI-6). The change in peak area in the SEC chromatograph suggests PAM concentration decreased from 717 to 105±3 mg/L, suggesting 85% total loss of PAM, which is likely due to both adsorption to the shale and chemical degradation (Table SI-3). The relative mass loss contribution to each effect will be discussed more in detail in the following section.

Controlling factors governing polymer degradation ACS Paragon Plus Environment


Degradation of PAM is found to be temperature dependent and pressure independent. Experiments were performed by incubating the raw fracturing fluid at atmospheric pressure (1 bar), 83 bar and 276 bar while maintaining a consistent temperature of 80oC and a shale loading of 25 g/L. The effect of pressure on iron concentration and peak MW are summarized in Fig. 2A. The peak MW was largely independent of pressure, with values after 24 h incubation ranging from 200 kDa at 83 bar to 300 kDa at 1 bar compared to the initial 10 MDa. Additionally, there was no change in total iron dissolved or solution pH (data not shown) over this range of pressures, suggesting that pressure has no significant effect on either iron dissolution or PAM degradation in these experiments. In contrast to the pressure experiments in Fig. 2A, temperature had a significant effect on PAM degradation (Fig. 2B). We compared samples obtained at room temperature, 50℃, and 80℃, after incubation with 25 g/L shale; the experiments were performed at atmospheric pressure to facilitate sampling (based on the relative lack of pressure dependence seen in Fig. 2A) with the data shown in Fig. 2B. There are two data points at time “0 h”; one is the raw fluid and the other is the sample taken 30 min after mixing with shale and ramping the temperature up to 80℃. The data at 80℃ show a large reduction in peak polymer MW throughout the 24 h reaction period, with a higher rate of degradation during the first 5 h (reduction by one order of magnitude) and a slower decrease from 1000 to 300 kDa over the remaining 19 h. In contrast, the data at both room temperature and 50℃ show an initial reduction to a peak MW of approximately 4,000 kDa during the temperature ramp, which then remains nearly constant throughout the rest of the experiment. Previous stability studies using hydrolyzed PAM also reported greater viscosity loss after incubation at 90 ℃ compared to that at room temperature40. Interestingly, we observed a quick initial drop of molecular size, roughly by a half MDa, from the raw fluid to the synthetic flowback fluid after the initial 30 min temperature ramp (Fig. 2B-inset). This initial shift happens much faster than the size reduction during the following 5 h. On careful examination of the data, we observe this rapid initial size reduction only occurs in the presence of shale and is independent of temperature, salinity or oxygen levels (Fig. 2). We conclude that the initial drop in MW is due primarily to adsorption of the high MW PAM to the shale at a relatively fast rate (compared to later chemical degradation).


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Salinity and hardness have only a small effect on chemical degradation of PAM. Raw FR fluid was prepared using 1.5 M CaCl2 or 3 M NaCl (roughly 170,000 mg/L total dissolved solids) to achieve a high salinity environment that represents a typical flowback and produced water quality. The results in Fig. 2C demonstrate that there are no considerable differences in final polymer size after a 24 h incubation in water compared to that in the different salt solutions. For example, the final peak MWs are 580, 320, 250 kDa for 1.5 M CaCl2, no additional salinity (control), and 3 M NaCl, respectively. A previous study found transformation of glutaraldehyde biocide was highly inhibited under high salinity due to hindered reactivity or formation of intermediate products43. Our results suggest this effect does not occur for PAM under the experimental conditions employed in this study. The presence of shale plays a very critical role in polymer degradation. We examined the effect of shale on the degradation of PAM by incubating the raw fracturing fluid without shale (0 g/L shale) or in the presence of 25 or 50 g/L shale loadings at 80 oC and 1 bar (Fig. 2D). These data were obtained at 1 bar to simplify the experiments; the results at high pressure should be similar based on the data in Fig 2A. There is very limited size reduction to 5 MDa from 10 MDa in the absence of shale, compared to the two orders of magnitude size decrease in the presence of shale under aerobic conditions. The behavior in the presence of 25 and 50 g/L shale were similar, with a slightly greater reduction in final polymer size (120 kDa compared to 320 kDa) for the higher shale loading. Upon the addition of shale, the level of dissolved iron was increased up to ~ 1.5 mg/L after the 24 h incubation and the solution pH was decreased to 3.5. Moreover, additional experiments performed with two Marcellus core samples with different pyrite/calcite molar ratio indicate that the mineralogy of the shale plays a critical role in polymer degradation. As shown in Table 2, core 6 caused an order of magnitude greater degradation in PAM than the outcrop shale sample, resulting in a final peak MW of 38 kDa and a solution pH of 3.2. In contrast, core 4 caused 10 times less degradation than the outcrop shale sample, resulting in a MW of 4,300 kDa and a solution pH of 3.8. Core 6 also released a much higher concentration of dissolved Fe (39 mg/L) compared to outcrop shale sample (1.5 mg/L) and core 4 ( 200 μg/L over a week at either 23 or 90℃ 40. This mechanism also explains the slightly higher degradation observed with 50 g/L shale loading compared to 25 g/L (after the 24 h incubation). We further measured the final mass of polymer by the end of the reaction with 1.5 ppm Fe2+ (24 h) to be 314 mg/L, suggesting polymer loss due to oxidative degradation was 50% (Table SI-3). The polymer loss due to adsorption was then calculated to be 35% (given 85% total polymer loss). Dissolved oxygen. Significant levels of dissolved oxygen are essential for the chemical degradation of polymer. Fracturing fluid will carry ambient concentration of oxygen (8 ppm) into the gas formation during fracturing, as discussed by others40, 56. The oxygen level in the fluid is sustained during pumping until contact with the anoxic shale formation. High salinity as a result of brine mixing with fracturing fluids will decrease oxygen solubility, although it can take up to 20 days to reach complete mixing4, which is much longer than the 24 h degradation time examined in this study. Equations (2) and (5) clearly demonstrate the important role of oxygen in PAM degradation, both in the initial autoxidation of Fe2+ and in the formation of peroxyl polymer radicals that further decompose to polymer fragments. Data obtained under anoxic conditions (Fig. 3D) show a much smaller reduction in polymer size than seen under aerobic conditions. Reaction without the addition of shale and under anoxic conditions showed almost no change in the peak MW. Note that without shale but in the presence of ambient dissolved oxygen (Fig. 2D gray square), there is still a small decrease in peak molecular weight (from 10 MDa down to 5 MDa), which was absent under anoxic conditions (Fig. 3D gray squares). This observation is consistent with


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the slow reduction in viscosity of hydrolyzed PAM in the presence of 8 mg/L initial dissolved oxygen concentration even with no Fe2+ present40. The comparison between aerobic and anoxic experiments clearly shows the critical role of oxygen in polymer degradation. As shown in Fig. SI-10, estimates of total oxygen in the system before and after reaction suggests the PAM degradation consumed 15 μmole O2 compared to the 82 μmole of PAM initially in the reactor. An additional experiment in which oxygen was removed from the headspace in the reactor showed only 4 μmole O2 was consumed, with a lower level of polymer degradation (final MW of 450 kDa compared to 260 kDa in the case with oxygen in the headspace). These experimental data clearly support the hypothesis that the ambient level of O2 is sufficient for polymer degradation given the polymer concentration and reaction conditions. We propose that the molecular weight reduction of PAM in the commercial FR under HVHF conditions is due to a free radical induced chain scission. The loss of PAM is also a result of adsorption to the shale. The summarized reaction scheme for the degradation pathway is presented in detail in Fig. 4B. We hypothesize that PAM degradation is initiated by hydrogen abstraction from PAM by hydroxyl and peroxyl radicals, generating polymer radicals (Eqn 1) at elevated temperature (80℃). Thermal conditions alone cannot cause this initial polymer radical generation as PAM is thermally stable up to 200℃

34

. Hydroxyl and peroxyl radicals are generated by

autoxidation of Fe2+ dissolved from shale at mg/L levels in the presence of ambient dissolved oxygen (reactions 5-8)53. Polymer radicals are then generated, with the three possible radical sites identified by Gröllmann and Schnabel

39

shown by dots in Fig.

4A. Polymer radicals react with dissolved oxygen forming polymer peroxyl radicals at diffusion-controlled rates as suggested previously (Eqn 2). The subsequent decomposition reaction is likely due to a bimolecular reaction suggested previously that involves the formation of macromolecules with two polymer peroxyl radicals and polymer oxyl radicals, which will further decompose to polymer fragments and radicals (Eqn 3-4)39, 57. The polymer fragments can then be attacked by hydroxyl radicals that continue the chemical degradation reaction. FTIR spectra suggest carbonyl groups potentially associated with ketone, aldehyde and carboxylic acid groups are newly generated in the polymer fragments. Fig. 4C shows distinct peaks 4 and 5 at 2808 cm-1 and 1720 cm-1 in both flowback with shale or with Fe2+compared to the spectrum of raw FR. Peak 4 is due to the C-H stretch of aldehydes and peak 5



can be assigned to C=O stretching vibration of aldehydes / ketones as well as carboxylic acids58. Moreover, the decrease in CHx based on XPS (Table SI-4) supports the breakage of the carbon backbone of the polymer, and an increase in O-R content further suggests the incorporation of oxygen during degradation. The detailed chemical structure of the PAM degradation products will need to be determined using techniques such as mass spectrometry and nuclear magnetic resonance. In addition to chain scission, XPS and ATR-FTIR analyses strongly indicate the occurrence of acid hydrolysis of PAM at 25 g/L shale, 1 bar, 80℃ and no additional salinity, where the amide groups are converted to carboxylic acid groups generating ammonium salts (Fig. 4D). XPS analysis suggests the content of carboxylic acid groups in PAM increased from 18% to 44% (Table SI-4) after reaction. FTIR spectra show a distinct peak 3 at 3042 cm-1 in flowback samples as evidence of ammonium salts being generated58. We also measured the ammonia concentration in synthetic flowback to be 7.8 ppm compared to the 2.3 ppm in the synthetic fracturing fluid. FTIR spectra also suggest that the newly generated -COO- groups are in protonated form and not associated with any cation such as sodium (the disappearance of peak 7 at 1554 cm-1 and generation of peak 5). The hydrolysis of amide groups of PAM was previously found to increase at acidic conditions (pH 4) and elevated temperature34, 59. As acidic conditions are essential in releasing Fe2+, acid hydrolysis is likely to occur simultaneously with radical induced chain scission. Note that the hydrolysis reaction would not cause a significant reduction in the molecular weight of the PAM59.

Environmental implications Our findings have significant environmental relevance, as PAM is a major organic component in HVHF fluids as well as in flowback water whose environmental fate and risks remain unclear. Our findings suggest that fracturing polymers will experience various extents of degradation depending on HVHF conditions, even without the addition of an oxidative breaker. Our results also provide insights into trends in degraded polymer size present in the flowback and produced waters (in the absence of breaker) based on formation mineralogy and reservoir temperature. Under the experimental conditions examined in this work, the final polymer size ranges from 200 kDa to 10 MDa, which corresponds to 80 to 350 nm in diameter. In a cooler formation (< 50℃), such as in some Marcellus shale regions, polymer degradation is unlikely to be initiated within 24 h although it might occur over extended periods of ACS Paragon Plus Environment

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time. One can also expect enhanced degradation to occur in deeper reservoirs with higher temperatures, such as Haynesville shale with a temperature as high as 200℃. Note that thermal degradation of PAM is also likely to occur via intramolecular and intermolecular imidization under these very high temperature conditions, leading to release of ammonia34. A high level of degradation can also be expected in formations that contain excess pyrite (relative to calcite). The Bakken, Barnett, Haynesville, Marcellus, and Woodford shales are more likely to have excess pyrite compared to the Eagle Ford and Antrim shales46. Early flowback water from multiple HVHF sites in the Marcellus shale can contain iron ranging from 0.03-600 mg/L5, which originates from both the shale and the iron-containing brine that mixes with the fracturing fluids. A higher initial iron concentration will likely lead to a higher rate of PAM degradation. Pyrite oxidation is a competitive source for oxygen consumption in deep subsurface, however a high content of pyrite significantly accelerates polymer degradation. Previous estimates suggest that pyrite is in excess compared to oxygen, in contrast to the excess oxygen in the experiments conducted in this study. Further investigation is needed to elucidate the relative kinetics of these two reactions. Note that radical scavengers and oxygen removal are both used in conventional polymer flooding40; we were not able to find any evidence for such uses in HVHF operations based on drilling logs at FracFocus.org8. Other potential degradation pathways also exist for PAM including: mechanical degradation during fluid pumping and transport to / from the perforation and formation fractures34; chemical degradation by the oxidative breaker added in the middle or post HVHF37,

50

; thermal34 or thermo-oxidative degradation under

more extreme conditions for an extended period of time; and possible microbial degradation35 by naturally occurring microbes60. The reduced size of the PAM can affect multiple wastewater management processes that are currently in use or under exploration. Current flowback and produced water management practices include direct disposal or reuse for subsequent HVHF; the latter involves mixing the flowback wastewater with fresh water before pumping downhole to fracture a new formation. The presence of low MW degraded polymers with nanometer size could potentially damage tight shale pores with nanometer to micron size during reuse of flowback water. There is also a growing need to develop effective and sustainable treatment methods leading to the



investigation of various membrane processes for treating flowback and produced waters2 including microfiltration, ultrafiltration3, 4, as well as forward osmosis5, 6 and membrane distillation2, 7. The lower MW polymer residue formed by exposure of PAM to HVHF conditions could lead to severe fouling of membranes which have pores ranging from micron to sub nanometer size. In addition, size reduction also might affect the mobility of degraded PAM in the environment; very low MW polymers (less than 1 kDa) would tend to act like dissolved organic matter compared to the polymers with >1 MDa size present in raw fracturing fluids. Lastly, it is possible that the degraded PAM could potentially lead to the generation of acrylamide (a neurotoxin) and other unknown toxic degraded products. More detailed studies will be needed to fully characterize the chemical structures and compositions of the degraded PAM products under HVHF conditions (using high-resolution chemical analyses14) and to identify potential toxicity using appropriate bioassays. We also suggest future studies specifically examine the fate and transport of degraded PAM in the environment, as well as the possible presence of very low levels of acrylamide in flowback and produced waters released via accidents such as surface spills and well casing leakage.

ASSOCIATED CONTENT Supporting Information The Supporting Information is available free of charge on the ACS Publications website at DOI: xxxx. Supporting information includes experimental materials and methods as well as raw data of XRD, EDS, nitrogen adsorption, TGA, FTIR, Mössbauer spectroscopy and XPS used for outcrop shale and polymer characterization, iron measurement, calibration curves of polymer standards, oxygen profile and data from control experiments testing the effect of low pH.

AUTHOR INFORMATION Corresponding Authors *Andrew Zydney, Email: [email protected]. Phone: +1 814-863-7113. *Manish Kumar, Email: [email protected]. Phone: +1 814-865-7519. Notes The authors declare no competing financial interest.


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ACKNOWLEDGEMENTS This research was funded by a Penn State College of Engineering Innovation Grant and a seed grant through the Center for Collaborative Research in Intelligent Gas Systems (CCRINGS) program funded by General Electric (GE). Additional funding comes

from

Pennsylvania

Water

Resources

Research

Center

Small grants program. The authors would like to thank Weatherford Inc. for providing the synthetic chemical additives. The authors acknowledge the Kappe Environmental Engineering laboratories for providing access to TOC measurement instrumentation and technical assistance provided by David Jones. We acknowledge help from Sydney Stewart on the iron and anoxic tests, and the Penn State Material Characterization Lab (MCL) staffs, specifically Nicole Wonderling (XRD), Julie Anderson (EDS), Jeff Shallenberger (XPS), Josh Stapleton (ATR-FTIR) and Ekaterina Bazileskaya (TGA). The authors also thank Prof. Alexey Silakov (Penn State Department of Chemistry) for guidance on free radical measurements.

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Table 1. Peak molecular weight, TOC and pH of synthetic and flowback fluids. Values are the average of three replicate experiments. Synthetic flowback was the product solution after incubation of the raw fluid with 25 g/L shale at 80℃ and 83 bar followed by centrifugation to remove shale debris.

Peak molecular weight (kDa) TOC (mg/L) pH

Synthetic fracturing fluid

Synthetic flowback

9500 ± 4000 230 ± 20 7.2 ± 0.5

200 ± 18 70 ± 21 3.9 ± 0.2



Figure 1. (A) From left to right: Friction reducer (FR) stock from Weatherford International, raw FR fracturing fluid (0.15% v/v), synthetic flowback water from reaction at 80℃, 83 bar and with 25 g/L shale (shale removed by centrifugation). (B) SEC Chromatograph of PAM in raw fluid (solid black), in synthetic flowback fluid (same reaction condition as described in A, red dash), and in non-ionic PAM standard with 6,500 kDa peak MW at a concentration of 0.5 mg/ml (blue dot dash). The top x-axis is calculated based on the calibration curve (SI-Fig. 4B) and the corresponding elution volume. The reaction was conducted at aerobic condition.


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Figure 2. Effect of pressure, temperature, salinity, and shale on PAM degradation. (A) Effect of pressure. High pressure has little impact on the peak MW (gray bars) and total dissolved iron concentration (blue circles) in synthetic flowback water after reaction with 25 g/L shale at 80℃ for 24 h. (B) Effect of temperature. Peak MW of PAM incubated at 80 ℃ decreased more significantly than at 50℃ and room temperature (RT). Both reactions were conducted with 25 g/L shale and at 1 bar. The first two points at 0 h are raw synthetic fluid (raw) and after mixing with shale followed by a temperature ramp up to 80 ℃ (after ramp), the difference can be better seen in the inset figure. (C) Effect of salinity. Similar decrease of polymer peak MW after incubation without added salt (gray squares) and with additional 3 M NaCl (blue diamonds) or 1.5 M CaCl2 (red circles) at 80℃, 1 bar and with 25 g/L shale. (D) Effect of shale. Peak MW declined one order of magnitude more in the presence of 25 g/L or 50 g/L shale than in the absence of shale. The reactions were conducted at 80℃ under 1 bar and aerobic conditions.



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Table 2. Comparison of PAM degradation and dissolved Fe content after incubation of friction reducer with Marcellus core samples and outcrop shale sample (25 g/L shale, 0.15% v/v FR solution, 80℃, 1 atm, no additional salinity, aerobic condition, 24 h). Pyrite and calcite were determined previously using semi-quantitative XRD44. Core/ shale sample mixed with DI (no polymer) at the conditions described above was taken for measurement of total dissolved Fe. PAM has an original MW of 10 MDa. Shale sample Core 4 Core 6 Outcrop

Pyrite % 5.4 1 NA

Calcite % 8 0.4 NA

Pyrite/Calcite (molar ratio) 0.6 2.1 NA

Total dissolved Final peak Fe (ppm) MW (kDa)

Chemical Degradation of Polyacrylamide during Hydraulic Fracturing

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