Imbibition of Mixed-Charge Surfactant Fluids in Shale Fractures

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Imbibition of Mixed Charge Surfactant Fluids in Shale Fractures Saikat Das, Jubilee T. Adeoye, Indu Dhiman, Hassina Z. Bilheux, and Brian R. Ellis Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b03447 • Publication Date (Web): 26 Feb 2019 Downloaded from http://pubs.acs.org on March 10, 2019

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Imbibition of Mixed Charge Surfactant Fluids in Shale Fractures Saikat Das1, Jubilee Adeoye1, Indu Dhiman2, Hassina Z. Bilheux2 and Brian R. Ellis1*

1Department

of Civil and Environmental Engineering, University of Michigan, Ann Arbor, MI

48109, USA 2Chemical

and Engineering Materials Division, Oak Ridge National Laboratory, Oak Ridge, TN 37831, USA * Author to whom correspondence should be addressed. E-mail: [email protected]. Tel: +1734-763-5470

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ABSTRACT Hydraulic fracturing of shale reservoirs often requires millions of gallons of water but only a fraction of the injected water returns to the surface. Shale gas production has been demonstrated to be positively correlated with the amount of water imbibed by the shale. In this study, neutron radiography is used to evaluate the effect of two commonly used surfactants in hydraulic fracturing fluids on the rate of capillary water uptake in shale fractures. Cationic n-octadecyl trimethyl ammonium chloride (OTAC) and anionic ammonium dodecyl sulfate (ADS) were added to DI water at 1:1 molar ratio at different concentrations and imbibed into a 200 μm Marcellus shale saw-cut fracture. The correlation between the surfactant concentration and fracture aperture with the capillary pressure and water uptake were examined in detail to understand water imbibition during hydraulic fracturing. The effect of wettability alteration during aging of the reservoir on the water uptake rate was studied by comparing water imbibition rates into shale fractures pre-exposed to the surfactant solutions to that of unexposed shale fractures. A 51% reduction in the rate of water uptake into the unexposed shale fracture was observed when the 1:1 mixed ADS/OTAC surfactant concentration was increased from 0.1 mM to 0.9 mM. This decrease in imbibition rate is attributed to changes in interfacial tension and not wettability alteration of the fracture surface. For the pre-exposed sample, surfactants have sufficient time to adsorb to the shale and alter the surface wettability. The rate of water uptake for pre-exposed shale fractures was reduced by 96% compared to unexposed shale fractures for 0.1 mM ADS/OTAC mixture. These experimental observations suggest that natural gas production may be improved after a well shut-in period when mixed charge surfactants are included in hydraulic fracturing fluid formulations and have sufficient time to alter shale wettability toward a more oil-wet state.

Keywords shale, unconventional reservoir, natural gas, surfactants, water uptake, neutron radiography


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1. INTRODUCTION The combination of advances in horizontal drilling technology, coupled with high volume hydraulic fracturing has allowed for the rapid development of shale gas reservoirs in the United States.1 Daily production of natural gas from U.S. shale reservoirs has increased by nearly 40% between 2005 and 2012 and now shale gas accounts for approximately 50% of U.S. domestic natural gas production.2 During hydraulic fracturing, millions of gallons of water, along with proppants and a range of chemical additives, are injected under high pressure in order to induce fractures in low permeability reservoirs. It is common practice to shut-in newly completed wells (i.e., close the wellhead and leave it under pressure) and let them ‘soak’ for a period of several weeks to months. After this shut-in period, the well is brought online and often only a small percent (~10 to 20%) of the injected water is recovered as flowback.3-5 Extensive water imbibition in low permeability rocks where water saturations are initially below irreducible saturation (a characteristic common of shale gas reservoirs) can often inhibit gas production due to the aqueous phase trapping near the fracture face.6-8 However, industry experience suggests an opposite trend for hydraulically fractured shales whereby the initial gas production rate has been shown to be positively correlated with increased water imbibition and longer soaking times.3, 9-11 Oil or natural gas produced from a reservoir due to the spontaneous imbibition of water into water-wet fractures or water-wet rock matrix by flowing in the opposite direction is a process known as counter-current flow.12,

13

This production process can be

enhanced through alteration of shale wettability and modification of invading fluid interfacial tension,6, 13, 14 both of which are key factors influencing water imbibition into shale fractures. Among all chemical additives used in hydraulic fracturing fluids, surface-active agents, such as surfactants, are an obvious component that can alter shale-water interaction and may ultimately control natural gas transport within the shale reservoir. Surfactants can adsorb on 3 ACS Paragon Plus Environment

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shale surfaces and, due to their amphiphilic nature (i.e., hydrophilic head and hydrophobic tail), can alter the surface wettability from water-wet to oil-wet or vise-versa based on different adsorption mechanisms (schematic of “headon” and “headout” interactions shown in Supporting Information Figure S1).15-17 Surfactant adsorption mechanism is dependent on several factors including surfactant head group structure, tail length, surfactant concentration, solvent property, surface charge and solution pH.18-23 Due to the synergistic properties of cationic (positively charged head group) and anionic (negatively charged head group) surfactants, mixtures of charged surfactants along with nonionic (neutrally charged head group) are often used to tune the wettability of desired surfaces.24, 25 Although many studies have examined the influence of surfactants in promoting oil recovery from both conventional and unconventional reservoirs,14,

26-33

fewer studies have

examined the effect of surfactants on natural gas recovery from shales.34-40 Sun et al. demonstrated that the addition of nonionic surfactants can reduce both the rate and extent of brine (2% KCl) uptake in shale samples during imbibition.35 Rickman and Jaripatke reported the effect of different commercially available surfactant micro-emulsions on the contact angle, interfacial tension and gas relative permeability alteration in shale gas reservoirs.36 Their study suggested that low interfacial tension and higher contact angles are ideal to reduce capillary force and increase gas relative permeability in shale reservoirs. Shen et al. found that although shale permeability after imbibition of distilled water and an anionic surfactant (DWAS) were similar, the imbibed amount of DWAS was far less than that of the distilled water.37 Abdulelah et al. reported that use of the anionic surfactant, internal olefin sulfate (1 wt%), altered shale wettability to a more water-wet state, which resulted in decreased methane desorption.38 According to Ayoub et al., the methane adsorption isotherm increases in shales due to the


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addition of the amphoteric surfactant, Betaine.39 Al-Ameri et al. observed an increase in gas permeability in Marcellus shale due to use of a non-ionic surfactant, TritonX-100, as a pad fracturing fluid additive.41 Although these studies have examined wettability and gas permeability alteration in shales, a direct relation between mixed surfactant loading and water uptake rate in shale fractures has not yet been studied. Several studies have investigated water loss in shale reservoirs after hydraulic fracturing42-44 and examined controlling factors for water imbibition.14, 45, 46 Zhou et al. reported that the water loss in shales is highly affected by the clay content of the shale formation.45 They demonstrated that the salinity of the water used to stimulate a well can be tuned to reduce the water imbibition in shales based on known clay content. Takahashi and Kovscek also investigated the effect of different brine formulations and pH on spontaneous water imbibition in siliceous shales and found that the highest oil recovery was achieved at higher brine pH (pH 12) values.14 Water imbibition rate has also been shown to be influenced by shale bedding direction.46 The goal of this study was to evaluate the impact of mixed charge surfactant solutions on the rate of water imbibition in shale fractures, as surfactants additives used in fracturing fluids may serve to reduce capillary forces through alteration of interfacial tension and/or shale wettability. Changes in the rate and extent of water imbibition can be used a proxy to evaluate the likelihood for aqueous phase trapping of natural gas after imbibition of hydraulic fracturing fluids. Here, neutron radiography was used to measure the rate of water imbibition into shale fractures for a range of mixed charge surfactant loading conditions. Prior studies have reported neutron radiography as a powerful technique to study water imbibition in porous and fractured rocks.47-51 Although fluid imbibition into larger aperture fractures will be limited due to lower


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capillary pressure, capillary action within the smaller fractures (apertures ≤ 200 µm) will serve to distribute fluid further into the shale and thus impact the extent of fluid penetration into the shale pore matrix. Our results demonstrate how 1:1 mixtures of ADS/OTAC (two common surfactants used in hydraulic fracturing completions) impact the rate of capillary rise in uniform aperture shale fractures and promote a reduction in water uptake rates both during initial imbibition and after prolonged exposure to surfactant fluids. These results help to understand how surfactant additives may influence shale gas production after well shut-in by limiting aqueous phase trapping of in-place natural gas.

2. EXPERIMENTAL SECTION The cationic surfactant, n-octadecyl trimethyl ammonium chloride (OTAC, C21H46NCl,), and anionic surfactant, ammonium dodecyl sulfate (ADS, C12H29NSO4), were purchased as a solid (95% pure, Alfa Aesar) and as an aqueous solution (30% by mass, ALDRICH Chemistry) respectively. The hydrophilic heads of ADS and OTAC have anionic sulphate and cationic ammonium groups respectively (see SI Figure S2). ADS and OTAC were mixed in deionized (DI) water in 1:1 molar ratio at five total surfactant concentrations of 0.1, 0.3, 0.45, 0.9 and 8.0 mM. The mixed critical micelle concentration (CMC) of the 1:1 ADS/OTAC mixture is 0.426 mM,52 so the 0.1 and 0.3 mM concentrations are below the mixed CMC while the 0.45, 0.9 and 8.0 mM concentrations are above the mixed CMC. We choose to examine an ideal solution (DI water) without the additional of dissolved salts to isolate the influence of the surfactant additives on water imbibition. The Marcellus shale sample used in this study was gathered from an outcrop near Bedford, Pennsylvania and was cut into 7.0 cm × 1.8 cm × 1.2 cm rectangular slices by a watercooled diamond saw. Surfaces of the rectangular slices were hand-polished using successively 6 ACS Paragon Plus Environment

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finer sandpaper (400, 800 and 2000 grit) and were then roughened with 800 grit sandpaper uniformly in one direction to have a consistent surface roughness for all samples. Two such rectangular slices were then placed side by side separated by stainless steel spacers of varying thickness (100, 200, and 800 µm) at the top and bound tightly with Kapton® tape. The interface between the two shale surfaces mimics a longitudinal fracture with constant aperture equal to that of the spacer thickness. The shale surfaces were polished with sand paper in this study to have similar water flow path in the shale fracture for all the surfactant concentrations to compare. These constant aperture fractures can be considered as a single pore with radius equal to half of the aperture width. Figure 1(a) shows the experimental design. The top of the fracture was kept open during the experiment so that air can escape from the top of the fracture. Two types of shale fractures were used for this study, one had a fresh surface without prior exposure to surfactant solutions and the second was pre-exposed to surfactant solution prior to performing the imbibition experiments. The pre-exposed shale fractures were soaked in 1:1 ADS/OTAC mixtures of varying total surfactant concentrations for two hours and then oven dried overnight at 50 °C to remove the extra amount of water from the surface and to have a similar hydration level for all pre-exposed samples. After this, the shale fractures were prepared as previously described. Neutron imaging experiments were performed on the CG-1D beamline neutron imaging facility at the High Flux Isotope Reactor (HFIR), Oak Ridge National Laboratory (ORNL).53 The shale sample was mounted at the top rotation stage with a custom-made circular attachment and placed in front of a microchannel plate detector (MCP). The rotation stage was used to align the fracture with neutrons and it also had an air release option so that the water can come up into the fracture during capillary uptake. The MCP detector is made of stacked neutron sensitive


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microchannel plates and placed above a quad Timepix readout with a 28 cm × 28 cm field of view. A high purity aluminum cell was filled with water and placed on a table below the shale sample. A constant height of the water in the reservoir was maintained externally using a Mariotte bottle (experimental setup and assembled shale sample are shown in Figure S3). To initiate the experiment, the table was lifted carefully so that the water level in the reservoir just touched the base of the shale fracture (Figure 1(b)). The initial time (t = 0 sec) for the water uptake study was considered to be the time when the water begins to penetrate the fracture due to capillary suction after the bath first came into contact with the shale. Neutron radiographs were taken every 10 ms to measure the rate of water imbibition. For the 2D data analysis, the raw data were normalized using the iMARS software package54 with respect to the initial dry images so that the imbibed water could be resolved.54-56 The neutron absorption intensity versus time profile of the wetting front propagation was also completed using iMARS.

3. RESULTS AND DISCUSSION 3.1. Unexposed shale Figure 1(c) and 1(d) show the evolution of the water front along 200 µm wide air-filled Marcellus shale fractures through a series of neutron radiographs for 0.1 mM and 0.9 mM ADS/OTAC 1:1 mixtures, respectively (radiographs of water imbibition for all other surfactant concentrations are provided in Figure S4 in the supplemental information). The neutron radiographs were normalized by the initial dry image so that water is clearly visible (black). The normalized radiographs also show some scattered dark spots in the data as a result of absorption by organic matter present in the shale. At time t = 0 sec the water begins to penetrate the fracture due to capillary suction. Subsequent images follow the water front as it moves upward into the fracture over time. As is evident in Figure 1, the water front reached the top of the fracture (21.4 8 ACS Paragon Plus Environment

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mm) within 0.03 sec for the 0.1 mM ADS/OTAC 1:1 solution, whereas the 0.9 mM ADS/OTAC 1:1 solution only rose to a height of 11.3 mm in 0.05 sec. The water front for the 0.9 mM ADS/OTAC experiment was followed for another 20 sec but there was no further rise into the fracture. The results clearly demonstrate that the water imbibition was slower for 0.9 mM ADS/OTAC mixture compared to the 0.1 mM ADS/OTAC mixture. To quantify the water uptake rate, a 660 μm × 880 μm area was selected as a region of interest (ROI) surrounding the fracture and the gray scale intensity evolution for that ROI was extracted using iMARS (see supplement information Figure S5). Starting from the base of the fracture, a series of equivalent ROIs along the fracture were taken and the intensity profile was extracted to track the water uptake. The sudden decrease in the gray scale intensity indicates the time when the water front reached the ROI area along the fracture (Figure S5). We are not able to report error analysis of the uncertainty of each point due to low counts arising from the very small volume of water at each point in the fracture. Although an error analysis was not possible, the random uncertainty in a processed neutron image can be calculated by the following equation,57 ∆𝒕 =

𝟏

𝟐

(1)

µ 𝑰𝟎𝑨𝑻𝒏

Where n is neutron detection efficiency, I0 is the expected incident neutron fluence rate, A is the integration area, T is the integration time, and µ is the attenuation coefficient. For the MCP detector and the estimated water front propagation, the random uncertainty in a processed neutron image is about 0.15 mm which is quite low compared to our spatial resolution (0.66 mm* 0.88 mm). So the difference between the water uptake rate for different conditions can be comparable for all samples. Figure 2 shows the water front height vs square root of time for 0.1


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mM and 0.9 mM ADS/OTAC 1:1 mixture (see Figure S6 for curve fitting for additional surfactant concentrations). The water front propagation was plotted against the square root of time and used to measure the rate of water uptake along the fracture as, 𝑥

𝑠 = √𝑡

(2)

where s is the sorptivity coefficient, x is the wetting front height measured from the base and t is time. This method is commonly used to model the transient flow of water in unsaturated porous media.58, 59 For this study it is assumed the fracture can be modeled as a single continuous pore and as such, the water front height vs square root time model can be fit to measure the water imbibition rate.60 The initial slow water uptake up to 0.1 sec1/2 for both 0.1 mM and 0.9 mM mixtures was excluded from the linear fitting due to the roughness variation near the throat of the fracture similar to the result reported by other researchers.47 Linear regression R2 fits of 0.99 and 0.94 for 0.1 and 0.9 mM ADS/OTAC 1:1 solutions, respectively, demonstrate excellent correlation between the wetting front height and square root of time. The slope indicates the sorptivity of the fracture for each different surfactant solution. From Figure 2 sorptivity was measured to be 173.6 and 85.2 mm/sec1/2 for 0.1 mM and 0.9 mM ADS/OTAC 1:1 mixtures, respectively, indicating a 51% reduction in sorptivity (or the water uptake rate) in the shale fracture when the mixed surfactant concentration was increased from 0.1 mM to 0.9 mM. The two forces that may impact the rate of water imbibition into the fractures are gravity and capillary pressure. However, the effect of gravity can often be considered negligible compared to that of capillary pressure in controlling the rate of water imbibition into a fracture at early times.47 The observed reduction in water imbibition rate and extent of penetration into the fracture for the higher concentration of ADS/OTAC can thus be attributed to a greater reduction 10 ACS Paragon Plus Environment

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in capillary pressure for the 0.9 mM ADS/OTAC mixture compared to 0.1 mM ADS/OTAC mixture. The capillary pressure (Pc) is calculated as, 𝑃𝑐 =

2 ∗ 𝛾 ∗ 𝐶𝑜𝑠𝜃 𝑅

(3) where γ is the interfacial tension between the wetting and non-wetting phases, Θ is the contact angle and R is the pore radius. As shown in Eqn. 3, Pc is a function of contact angle, interfacial tension and pore radius. Here, the capillary diameter was equivalent in the two experiments (200 µm), so Pc in our experiments may be reduced due to either a decrease in interfacial tension or an increase in contact angle. Figure 3 shows sorptivity as a function of total surfactant concentration for ADS/OTAC 1:1 mixtures. The orange line Figure 3 shows the sorptivity for pure water. As is evident from Figure 3, for surfactant concentrations well below the CMC of the ADS/OTAC 1:1 mixture (≤ 0.3 mM) the sorptivity remains similar to that of pure water. This indicates that surfactant loading does not affect the water uptake rate in the shale fractures at low surfactant concentrations. As the mixed surfactant concentration increases (>0.3 mM) the sorptivity decreases suddenly and it continues to decrease with further increase in surfactant concentration. There is a 95.7% decrease in sorptivity as the surfactant concentration increases from 0.1 mM to 8.0 mM total surfactant concentration indicating strong dependence between sorptivity and total surfactant concentration (> 0.3mM). The solution pH will impact the surface charge of the shale surface.61, 62 Here, the initial pH of the DI water surfactant solution was approximately 5.6. It is expected that dissolution of calcite present in the shale, 49 wt% of total mineral composition,63 will increase the pH of the 11 ACS Paragon Plus Environment

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solution after contact with the rock, however, the point of zero charge pH (pHpzc) of calcite is quite high (pH 8-9.5) and the contact time is very short, so it is not anticipated that the surfactant adsorption mechanism on calcite surfaces will be ‘flipped’ due to pH changes as the pH is expected to remain below the calcite pHpzc.64 The pHpzc of illite, the main component of clay in shales,65 is also quite high (pH 9-10),66 so the surfactant adsorption mechanism on illite should also not be altered by pH changes in these experiments. Furthermore, a rise in solution pH will help the cationic surfactant (OTAC) to adsorb on the negatively charged quartz surface more strongly (quartz pHpzc  2.8).67 The salt concentration in the solution can also impact the adsorption of ionic surfactants.19, surfactant could precipitate.

70

68, 69

For example, in the presence of cations the anionic

Also, divalent ions can act as bridging molecules to adsorb more

oppositely charged surfactant headgroups on a charged surface, whereas monovalent ions can reduce the surfactant adsorption of similarly charged headgroups on a charged surface. Due to the uncertainty and variability of the total salt concentration present in a given shale reservoir during hydraulic fracturing, we chose to examine an ideal solution (DI water) without the additional of dissolved salts. Imbibition experiments were also carried out for a range of shale fracture apertures and surfactant concentrations both below and above the 1:1 ADS/OTAC mixed CMC of 0.426 mM. Figure 4 shows the comparison of sorptivity measured for ADS/OTAC 1:1 mixture of 0.1 mM and 0.9 mM total surfactant concentration for three different fracture widths of 100, 200, and 800 µm. For all fracture widths the sorptivity is much less for the 0.9 mM solution than for the 0.1 mM solution. This result demonstrates that for a total surfactant concentration of 0.9 mM, which is above the CMC of the mixture, the water imbibition is reduced significantly due to change in the capillary pressure.


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3.2. Mechanisms of attenuation of capillary pressure To examine the hypothesis that changes to both wettability and interfacial tension simultaneously reduce capillary pressure in the experiments, the relationship between capillary pressure and fracture aperture considering the influence of both alteration in surface wettability and interfacial tension for 0.1 mM and 0.9 mM ADS/OTAC 1:1 mixture is shown in Figure 5. The capillary pressure was calculated using equation 3 for aperture widths from 100 µm to 1000 µm with 100 µm intervals. In a previous study, the interfacial tension and contact angle alteration for Marcellus shale after contact with solutions containing 1:1 ADS/OTAC mixtures was reported for various surfactant concentrations both below and above CMC.63 This prior work demonstrated that both contact angle and interfacial tension decrease with an increase in surfactant concentration from 0.1 mM to 0.9 mM. The Pc curve given in Fig 5(a) takes into account both the measured contact angle and interfacial tension.63 The capillary pressure curves for both surfactant concentrations coincide due to the nullification of the two influences, contact angle and interfacial tension, as the surfactant concentration increases from 0.1 mM to 0.9 mM. For the 0.1 mM solution the contact angle is higher (i.e., cos𝝷 value is lower) but interfacial tension (𝞬) is higher compared to 0.9 mM, which leads to a nearly identical capillary pressure vs. aperture width relationship, following Eqn. 3, for both surfactant concentrations. If both wettability and interfacial tension alteration impact the water uptake rate simultaneously then the sorptivity could be expected to be the same for the 0.1 mM and 0.9 mM ADS/OTAC solutions at a given aperture width, however, there is clearly a decrease in sorptivity as the surfactant concentration is increased from 0.1 to 0.9 mM (Figure 4).


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Figure 5(b) shows a plot of capillary pressure versus aperture width for a fixed contact angle of 50° to isolate the effect of changing interfacial tension on capillary pressure. The contact angle of 50° was selected to be in between the contact angle for 0.1 mM (55°) and 0.9 mM (45°) ADS/OTAC 1:1 mixtures.50 It is evident from Fig 5(b) that there is a reduction in capillary pressure (up to a fracture width of 800 µm) when the surfactant concentration is increased from 0.1 mM to 0.9 mM. The difference in capillary pressure at fracture widths of 100, 200, and 800 µm for the 0.9 mM surfactant solution compared to the 0.1 mM solution was 198, 99 and 25 N/m2, respectively. This reduction in Pc at higher surfactant concentrations explains the observed reduction in the rate and extent of water imbibition for 0.9 mM ADS/OTAC mixture compared to the 0.1 mM solution and suggests that wettability alteration due to surfactant adsorption on the shale surface did not influence the rate of water imbibition in these experiments. 3.3. Pre-exposed shale To further explore the role of surfactant adsorption on the rate of water imbibition into fractured shales, a series of imbibition experiments were carried out with shale fractures that were pre-exposed to surfactant solutions. Shale samples were soaked in surfactant solutions at concentrations ranging from 0.1 mM to 8.0 mM prior to performing these imbibition experiments. This pre-exposure ensured that the surfactants had sufficient time to attach to the shale surface and thus alter the shale wettability. Imbibition experiments were conducted with solutions corresponding to the surfactant concentration used for each pre-exposed shale sample (i.e., 0.1 mM pre-soaked sample is used in 0.1 mM imbibition experiment) and the measured sorptivity was compared with that of the unexposed shale fractures (see Figure S7). Figure 6 shows the comparison of sorptivity for both pre-exposed and unexposed shale fractures (200 µm aperture) at different surfactant loading conditions. As is evident from Figure


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6(a), the sorptivity for pre-exposed shale fractures was significantly reduced compared to that of the unexposed shale fractures for all surfactant concentrations. The difference in sorptivity is larger (96% reduction for pre-exposed shale fracture at 0.1 mM ADS/OTAC 1:1 mixture) at low surfactant concentrations (≤ 0.3 mM). At surfactant concentrations just above the CMC (at 0.45 mM) the difference between sorptivity for pre-exposed and unexposed shale surfaces is smaller (55% reduction for pre-exposed shale fracture) and at higher surfactant loading concentrations (> 0.45 mM) sorptivity for both unexposed and pre-exposed shale fractures decreases significantly. The greater reduction in sorptivity for pre-exposed shale samples at low surfactant concentrations (≤0.3 mM) can be explained by accounting for alteration of wettability due to surfactant adsorption. The contact angle (𝝷) shown in Eqn. 3 indicates the wettability of the shale surface. As the surface is altered from a strongly water-wet state toward a less water-wet state, the contact angle increases and this leads to a reduction in Pc. Figure 6(b) shows photos of water droplets used to measure contact angles for ADS/OTAC 1:1 mixtures at different surfactant concentrations on pre-exposed shale samples. At 0.1 mM surfactant concentration, which is below the CMC, the contact angle has the highest value (55°), and as the surfactant concentration is increased above CMC the contact angle decreases gradually. The contact angle result implies that at surfactant concentrations below CMC for a 1:1 mixture of ADS/OTAC adsorbed on a shale sample, the surface becomes more oil-wet which contributes to a reduction in capillary pressure compared to that for DI water. The change in contact angle may be better explained by the alteration of surfactant adsorption mechanism with increasing total surfactant concentration.

Figure 6(c) shows a

schematic for surfactant adsorption on the shale surface at different surfactant concentrations. According to Zhou et al.,63 at very low ADS/OTAC surfactant concentration (≤ 0.3 mM), the


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surface becomes more oil-wet due to the outward orientation of surfactant tails, which leads to an increase in contact angle and subsequently contributes toward a reduction of capillary pressure.63 Interfacial tension, the other contributor toward altering capillary pressure, remains unaltered compared to pure water at low surfactant concentrations (≤ 0.3 mM) and decreases suddenly at surfactant concentrations above the CMC of the mixed surfactant solution (0.426 mM). There is no further decrease in interfacial tension above CMC as surfactants do not remain surface active above CMC.71,

72

The alteration in wettability at low surfactant concentrations (≤ 0.3 mM)

decreases the capillary pressure for pre-exposed shale fractures and leads to significant reduction in water uptake rates compared to pure water. Water imbibition into ‘unexposed’ shale fractures, such as will occur during and directly after hydraulic stimulations, will therefore not likely be influenced by surfactant alterations to shale wettability as the surfactant will not have sufficient time to adsorb on the shale surface. No wettability effect was observed on capillary pressure for unexposed shale fracture due to lack of surfactant adsorption at the fracture interface. The interfacial tension also remains unaltered compared to pure water at low surfactant concentration (≤ 0.3 mM). Consequently, due to the unaltered surface wettability and interfacial tension the sorptivity for unexposed shale fractures remains similar to pure water at ADS/OTAC 1:1 surfactant concentrations up to 0.3 mM. Due to the drastic reduction in capillary pressure for pre-exposed shale fractures, the difference in sorptivity is larger between unexposed and pre-exposed shale fractures at surfactant concentrations up to 0.3 mM. With further increases in surfactant concentration above the CMC (>0.426 mM), the surface becomes less oil-wet due to formation of a surfactant bilayer (Figure 6(b)), which leads to a decrease in contact angle that contributes toward an increase in capillary


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pressure. Interfacial tension decreases significantly near the CMC and this contributes toward a decrease in capillary pressure. There is a net decrease in sorptivity due to the combined alterations of wettability and interfacial tension for pre-exposed shale fractures, while for unexposed shale fractures only interfacial tension impacts sorptivity near the CMC, resulting in a net decrease in sorptivity for surfactant concentration of 0.45 mM. Due to the opposite trend in capillary pressure alteration at 0.45 mM ADS/OTAC surfactant concentration (just above CMC), the difference of sorptivity between the unexposed and pre-exposed shale fracture is reduced compared to low surfactant concentrations (≤ 0.3 mM) (Figure 6(a)). With further increase in surfactant concentration (> 0.45 mM), although the contact angle decreases (Figure 6(b)) due to formation of a denser bilayer (Figure 6(c)), the viscosity of the solution increases linearly with surfactant concentration due to increase in frictional force between solution and micelles.73 The increase in viscosity leads to a significant reduction in sorptivity for both unexposed and pre-exposed shale fractures at surfactant concentrations about the mixed surfactant CMC (> 0.45 mM). In the case of preexposed shale fractures, as the surface wettability still remains more oil-wet compared to pure water, the sorptivity is further reduced (Figure 6(a)) compared to unexposed shale fractures where changes in wettability do not have any effect on the water imbibition rate. Results from this study indicate that during initial shale fracturing, alteration of wettability is unlikely to influence the rate of water uptake due to the fast rate of imbibition relative to surfactant adsorption. This is due primarily to the fact that the contact time between the surfactant solution and the shale surface is insufficiently long relative to that of the imbibition rate such that surfactant adsorption will not influence capillary pressure. According to Paria et al. the required time to get surfactant solid phase concentration >90% of final solid phase


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concentration for the adsorption of cationic surfactant cetyltrimethyl-ammonium bromide (CTAB) and anionic surfactant sodium dodecylbenzene-sulfonate (NaDBS) on a cellulose surface was approximately 50-60 minutes.74 ADS and OTAC should have similar adsorption kinetics during the adsorption on the shale surface. In this study, the total water uptake time (< 1.0 sec) was much smaller compared to the require time to get >90% of final surfactant solid phase concentration for ADS and OTAC to adsorb on the shale surface. As a result, only the changes to interfacial tension impact the extent of capillary rise or the water uptake rate for unexposed shale fractures. For example, at 0.9 mM surfactant concentration the interfacial tension is significantly lower than at 0.1 mM and there is a reduction in the water imbibition rate. The situation changes when the shale fractures were pre-exposed for 2 hours to surfactant solutions prior to carrying out the water uptake experiments, as this contact time allowed for surfactant adsorption on the shale surface and alteration of shale wettability. At low surfactant loading conditions (≤ 0.3 mM) the surface becomes more oil-wet compared to pure water due to the outward orientation of the hydrophobic tail of the surfactants. The increase in contact angle caused by the surfactants leads to a reduction in capillary pressure and ultimately reduces the water imbibition rate. This is why the water uptake decreases dramatically for pre-exposed shale fractures compared to unexposed shale fractures at surfactant concentrations below the CMC (Figure 6(a)).

4. CONCLUSION This work has demonstrated that initially following the well stimulation process, surfactant additives will only serve to impact water imbibition via a reduction in interfacial tension. Given longer contact times (several hours to days) the mixed cationic/anionic surfactants have the


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capacity to alter shale wettability toward a more oil-wet state and inhibit continued capillary suction of fracturing fluids further into the shale. Such alterations to shale wettability may create conditions that are more favorable for gas transport either through counter-current gas flow or improved gas relative permeability, thereby preventing well damage commonly associated with aqueous phase trapping in shale reservoirs with sub-irreducible initial water saturations. This may be a contributing factor to help explain why sufficient aging of the reservoir during shut-in periods can promote higher natural gas production rates.



ACKNOWLEDGEMENTS

The authors would like to acknowledge the donors of The American Chemical Society Petroleum Research Fund for support of this research. A portion of this research used resources at the High Flux Isotope Reactor, a DOE Office of Science User Facility operated by the Oak Ridge National Laboratory, under contract number DE-AC05-00OR22725. The authors would also like to thank Louis J. Santodonato for his contribution during instrument setup at ORNL CG-1D beamline and Jean C. Bilheux for his contribution on IMARS development and data analysis.

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ASSOCIATED CONTENT

Supporting Information Schematic diagram of (a) headon and (b) headout interaction of surfactant with the charge surface (Figure S1); Molecular structures of (a) OTAC and (b) ADS determined by geometry optimization using the PM3 semiempirical molecular orbital method as implemented in the program Avogadro (Figure S2); Pictures of (a) Experimental setup and (b) assembled sample with Shale 200 µm fracture aperture (Figure S3). Shale assembly with 200 µm fracture aperture.(Figure S3),Time sequence of radiographs for 0.3 mM

ADS/OTAC, 0.45 mM and 8.0 mM ADS/OTAC solutions (Figure S4); Example data analysis of water propagation in a shale fracture (Figure S5); Wetting front position as a function of the square root of time for 0.3 mM ADS/OTAC, 0.45 mM ADS/OTAC and 8.0 mM ADS/OTAC 19 ACS Paragon Plus Environment

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solution (Figure S6); Wetting front position as a function of the square root of the time for both unexposed and pre-exposed shale fractures for 0.1 mM ADS/OTAC, 0.3 mM ADS/OTAC, 0.45 mM ADS/OTAC and 8.0 mM ADS/OTAC solution (Figure S7).

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Reference

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Figure 1: Schematic of the shale water imbibition experiments. The unexposed shale fracture was positioned above a water bath (a) and at t = 0 seconds when the water bath contacts the base of the fracture (b). Time sequence of neutron radiographs showing rapid water uptake into longitudinal shale fractures for (c) 0.1 mM ADS/OTAC and (d) 0.9 mM ADS/OTAC solutions. The images have been normalized using IMARS so that water is clearly visible (black). The final height of the wetting front is denoted next to the last image (0.03 sec for 0.1 mM ADS/OTAC and 0.05 sec for 0.9 mM ADS/OTAC mixture) for both the cases. 206x188mm (300 x 300 DPI)

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Figure 2: Wetting front position in the unexposed shale fracture as a function of the square root of the time for (a) 0.1 mM ADS/OTAC solution and (b) 0.9 mM ADS/OTAC solution. This slope of the fitted data (R2 > 0.90) represents the sorptivity or the water uptake rate for each case. The water uptake rate is reduced by 51 % when the mixed surfactant concentration is increased from 0.1 mM to 0.9 mM. 139x78mm (300 x 300 DPI)


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Figure 3: Change in sorptivity of the unexposed shale fracture with aperture width of 200 ��m at varying total surfactant concentrations of ADS/OTAC 1:1 mixture. The orange line represents the sorptivity of pure DI water and the gray line represents the CMC of the mixture. The vertical bars correspond to standard error associated with each data point.


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Figure 4: Change in sorptivity of unexposed shale fracture at different aperture widths for 0.1 mM and 0.9 mM ADS/OTAC 1:1 mixture. The vertical bars correspond to standard error associated with each data point. 145x73mm (300 x 300 DPI)


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Figure 5: Capillary pressure vs fracture aperture width (diameter) for (a) measured contact angle and interfacial tension and (b) fixed contact angle (50°) and measured interfacial tension for 0.1 mM and 0.9 mM ADS/OTAC 1:1 mixtures. 265x76mm (300 x 300 DPI)


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Figure 6: Effect of ADS/OTAC 1:1 surfactant mixture adsorption on Marcellus shale surface. (a) Comparison between sorptivity in unexposed and pre-exposed shale fractures with aperture width of 200 ��m. The vertical bars correspond to standard error associated with each data point. (b) Water droplets for contact angle measurement for different surfactant loading conditions of 0.1, 0.45 and 8.0 mM ADS/OTAC 1:1 solutions on pre-exposed shales. (c) Schematic of proposed surfactant adsorption mechanism at different surfactant loading conditions of 0.1, 0.45 and 8.0 mM ADS/OTAC 1:1 solutions.


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Table of contents graphic 69x44mm (300 x 300 DPI)


Imbibition of Mixed-Charge Surfactant Fluids in Shale Fractures

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