Enhanced Oil Recovery Driven by Nanofilm Structural Disjoining

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Enhanced Oil Recovery (EOR) Driven by Nanofilm Structural Disjoining Pressure: Flooding Experiments and Microvisualization Hua Zhang, T. S. Ramakrishnan, Alex D. Nikolov, and Darsh Wasan Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b00035 • Publication Date (Web): 01 Apr 2016 Downloaded from http://pubs.acs.org on April 5, 2016

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Enhanced Oil Recovery (EOR) Driven by Nanofilm Structural Disjoining Pressure: Flooding Experiments and Microvisualization

Hua Zhang1,2, T. S. Ramakrishnan2, Alex Nikolov1, and Darsh Wasan1*

1

Department of Chemical and Biological Engineering, Illinois Institute of

Technology, Chicago, Illinois 60616, United States; 2

Schlumberger-Doll Research, 1 Hampshire St., Cambridge, MA 02139, United

States

* Author to whom correspondence should be addressed: [email protected] 1 ACS Paragon Plus Environment

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Abstract Nanofluids composed of liquid suspensions of nanoparticles, may soon permit accelerated recovery of hydrocarbons from oil and gas reservoirs. Here, we present a series of flooding experiments at different capillary numbers to quantify the performance of a polymeric nanofluid compared to brine using the sintered glassbeads. A high resolution X-ray microtomography (microCT) was used to visualize oil and brine distribution in a sintered bead-pack before and after nanofluid flooding. The results of flooding experiments showed that an additional oil recovery of approximately 15% is possible with nanofluids compared to brine at low capillary numbers, and is as effective as high capillary number brine flooding. Nanofluid induced additional oil recovery decreases as we increase the capillary number and the total oil recovered shows a marginal decrease. At first glance, these results are opposite of what one expects in the conventional EOR, where oil recovery is known to increase progressively with increasing capillary number. These results cannot be explained based on mobilization theories due to the reduced capillarity. Our results however are consistent with the mechanism of wettability alteration caused by structural disjoining pressure leading to the formation of the wetting nanofluid film between oil and substrate. Unlike brine displacement, X-ray micro-CT images show that mobilization of oil from the porous medium by a nanofluid is fairly uniform even at low capillary 2 ACS Paragon Plus Environment

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numbers and large-scale clusters of oil are absent. Our findings in this paper are expected to promote the understanding of EOR by nanofluids.

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1. Introduction Nanofluids, liquid suspensions of nanoparticles such as polymer latexes, globular proteins, and surfactant micelles, have recently become attractive agents for EOR from oil reservoirs.1-3 Researchers have observed positive results and an increase in ultimate oil recovery in laboratory experiments by injecting nanofluids.4-18 Ju et al.4-6 conducted experimental and theoretical studies on wettability alteration and permeability change caused by adsorption of lipophobic and hydrophilic polysilicon nanoparticles (LHP) on the surface of sandstone cores. From core displacement experiments, they observed LHP in the size range of 10– 500 nm could improve oil recovery by about 9% compared to water. Based on their numerical simulation, an LHP concentration of 2–3% percent by volume was suggested for EOR, since porosity and permeability declined through retention of LHP within the medium at higher concentrations. Babadagli et al.7 studied capillary imbibition using different surfactants and polymer solutions for enhancing oil recovery. They conjectured that the reduction in the interfacial tension between the aqueous phase and oil was the cause of faster and improved oil recovery.


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Onyekonwu and Ogolo8 reported the performance of polysilicon nanoparticles for enhancing oil recovery. Three different types of polysilicon nanoparticles were used for the displacement experiments on water-wet rocks: lipophobic-hydrophilic (LHPN), hydrophobic-lipophilic (HLPN), and neutrally wet nanoparticles (NWPN). They found that NWPN and HLPN were good EOR agents in water-wet formations while LHPN yield poor recovery factors indicating that its use for EOR should be restricted to oil-wet formations. These investigators inferred that EOR was due to both the reduction of interfacial tension and wettability change. Hendraningrat et al.9-13 examined the ability of hydrophilic silica nanoparticles to improve oil recovery. Some parameters influencing EOR processes, such as the size and concentration of nanoparticles, initial core wettability, nanofluid injection rate and temperature were investigated. They concluded that oil recovery improves with increasing temperature, decreasing nanoparticle size and decreasing injection rate. Additionally, the highest oil recovery was obtained from intermediate-wet rocks. They showed that EOR using silica based nanofluid resulted from the medium becoming water-wet from its oil-wet state. Moghaddam et al.14 compared eight different nanoparticles previously investigated in the literature. These were zirconium dioxide (ZrO2), calcium carbonate (CaCO3), titanium dioxide (TiO2), silicon dioxide (SiO2), magnesium oxide (MgO), aluminum oxide (Al2O3), cerium oxide (CeO2), and carbon nanotube 5 ACS Paragon Plus Environment

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(CNT). The ability to alter wettability of carbonate rocks was studied. Based on their impact on wettability alteration and stability in brine, CaCO3 and SiO2 were selected for spontaneous imbibition tests and core flooding experiments. The results of both imbibition and core flooding experiments demonstrated that SiO2 nanoparticles treatment improved oil recovery more than the treatment by CaCO3 nanoparticles, but over a longer duration. In summary, two classical mechanisms of EOR using nanofluids have been proposed, namely, the reduction of the interfacial tension between the aqueous phase and oil phase,7,15 and rock wettability alteration. 4-6,9-13,16,19 In some instances, both mechanisms are believed to be operational. 8,17,18 Despite of recently widely conducted research using nanofluid for EOR, the underlying operating mechanism of recovery by nanofluid is still not well understood. A new view of oil displacement from a solid substrate using a nanofluid was recently proposed by Wasan and Nikolov.20 In their paper, the nanoparticle structuring (layering) in the wedge film was advocated as the driving mechanism for the wettability alteration. They showed that nanoparticles (or surfactant micelles) form two-dimensional (2-D) layered structures in the confined threephase (solid-oil-aqueous phase) contact region of the wedge film (Figure 1). The nanoparticle structuring phenomenon gives rise to the structural disjoining pressure 6 ACS Paragon Plus Environment

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(a force normal to the interface) in the wedge film with a higher disjoining pressure near the tip of the wedge than in the bulk meniscus. As a result, the oil-nanofluid interface moves forward with a progressive cleaving of the oil-solid contact eventually detaching the oil drop.

Figure 1. Schematic presentation of mechanism of oil displacement driven by nanofluid structural disjoining pressure: nanofluid layering leads to film tension gradient and drives oil displacement.20

Kao et al.21 observed two distinct contact lines during the separation of crude oil droplets from a solid silica surface in the presence of a nanofluid (micellar solution) using a differential interference microscope: an outer one (between the oil, solid and water film) and an inner one (between the oil, solid and mixed oil/water film) (see Figure 2). The spreading of a mixed oil/water film was later understood 7 ACS Paragon Plus Environment

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to be driven by the structural disjoining pressure gradient arising from the ordering of the micelles in the wedge-film region by Wasan and Nikolov.20 Wasan, Nikolov, and their coworkers22-26 further noted that the dynamics of the inner contact line depend on the combination of the nanoparticle formulation, contact angle and the capillary pressure. A suitable combination of these factors accelerates the spreading of the nanofluid on the solid surface, thereby detaching the oily soil from the substrate.

Figure 2. Photomicrograph taken by reflected-light interferometry depicting the nanofluid structural disjoining pressure on oil displacement dynamics. The “outer


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line” is the macroscopic three-phase contact line and the “inner line” depicts the advancing nanofluid film driven by structural disjoining pressure.24 In the case of high salinity, the effective diameter (including electrical double layer) (and thereby the particle volume fraction) decreases, owing to the shrinkage of the electrical double layer around each particle. Therefore, the magnitude of the structural disjoining pressure diminishes, thus reducing the driving force for the detachment of the oil drop. The application of nanofluids was also explored for hydrocarbon recovery from oil saturated Berea sandstone.27 Compared to brine (containing 0.32 mol/L NaCl), an additional 30% of crude oil was recovered using IIT nanofluid at a reservoir temperature of 55 oC. High resolution X-ray microtomography (micro-CT) has been used extensively in the oil and gas industry for imaging, quantifying properties, and determining the distribution of fluids in porous rocks.28 The main advantage of X-ray micro-CT is the non-destructive nature of the technique that allows 3D monitoring of internal structural changes at resolutions in the range of a few microns.29,30 Extensive research on imaging the residual non-wetting phase using micro-CT scanning at ambient conditions where the porous medium was strongly water-wet or oil-wet has been done.31-38 Karpyn et al.34 experimentally investigated trapped oil clusters in a water-wet bead pack subject to different flow conditions using X-ray 9 ACS Paragon Plus Environment

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microtomography. They presented oil cluster shape and size distribution and found an average cluster size of approximately five pores. Our present paper is the continuation of the previous exploratory study27 and is related to the understanding enhanced oil recovery from a porous medium using IIT nanofluid (patent applied): a polymeric nanofluid (polyethylene glycol dispersed in brine) at different capillary numbers. Since these polymeric consists of particles in the range of about 10 nm (see below), and appear to be stable to salinity, they may be considered to be a nanofluid consisting of deformable particles. The primary purpose of our work with these fluids was to understand the removal of trapped oil ganglia (or clusters) formed by low capillary number brine flooding and comparing the results to brine injection at various capillary numbers, which mimic a conventional tertiary recovery process with reduced interfacial tension. Thus, the present study differs from the previous ones, since the objective here is to distinguish interfacial tension induced oil recovery from that due to wettability change by the structural disjoining pressure. The former reduces capillarity, whereas the latter may even enhance capillarity. Although we found that additional oil recovery was enabled by the presence of nanofluid, the incremental recovery decreased with increasing capillary number, while the total oil recovered showed a slight decrease. This non-intuitive result is understood by 10 ACS Paragon Plus Environment

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considerations of nanofluid film formation time-scale in relation to advection timescale. We provide detailed images of residual oil from X-ray micro-CT, both with nanofluid and brine, and contrast the results by relating them to wettability.

2. Experimental section 2.1. Materials. 2.1.1. Oil. Oil used in this study is Cargille immersion liquid (Cargille Laboratories, NJ, USA). Properties of the Cargille immersion liquid are given in Table 1.

Table 1. Oil properties (25 oC, 1 atm pressure) Property

Value

Density, g mL-1

0.854

Viscosity, Pa s

0.0181

Surface tension, mN m-1

29.4

Refractive index

1.474

A small amount (100 ppm) of Oil Red EGN dye (Aldrich Chemical Co., Milwaukee, WI) was added to the oil sample to increase visual contrast for observational ease.


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2.1.2. Brine solution. Brine was prepared by dissolving sodium chloride (NaCl, Fisher Scientific, USA) in deionized (DI) water. The concentration of NaCl was 0.25 wt% of solution. Density of brine was 0.99 ± 0.01 g/cm3 and pH was 6.5 ± 0.5 at 22 °C and 1 atm pressure. The viscosity of brine is 1.022 mPa s at 20 °C.

2.1.3. SDS solution. We prepared sodium dodecyl sulfate (SDS, VWR Scientific, USA) solution in brine to a concentration of 1.35 mM so that the SDS solution has the same interfacial tension with oil as that of nanofluid.

2.1.4. Polymeric nanofluid. Most reservoir environments are at high temperature, pressure, and salinity. Most nanofluids, such as silica nanoparticle dispersions are unstable and agglomerate in such environments. In contrast, a polymeric nanofluid containing polyethylene glycol 8000 (Fisher Scientific, USA) dispersed in brine, is relatively stable with respect to electrolytes or temperature. In order to enhance the effect of the structural disjoining pressure on the oil recovery process, the nanofluid composition was selected based on a multistep process.27,39 The size and polydispersity of the polymeric nanofluid in brine were characterized by the dynamic light scattering method (Malvern Instruments, UK). The average diameter was found to be 9.5±0.5 nm, with a polydispersity of around 8-10% at 25 12 ACS Paragon Plus Environment

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o

C. The concentration of nanofluid used in this study is 0.277 wt% or 10 v%

calculated based on the molar concentration of the polymer40. The density of nanofluid was 1.00 ± 0.01 g mL-1 with a pH = 6.5 ± 0.5 at 22 °C at 1 atm pressure and the viscosity of nanofluid is 1.097 mPa s at 20 °C. Table 2 shows the size and polydispersity of polymeric nanofluid at two different salinities. Table 2. Nanofluid size and polydispersity characterized by dynamic light scattering at different salinities at 25 oC. Concentration of NaCl (wt%)

Size (nm)

Polydispersity

0.025

10.5 ± 1.0

0.12-0.15

0.25

9.5 ± 0.5

0.08-0.1

The near constancy of average diameter and narrow dispersity even with varying salinity illustrates that the polymeric dispersion is stable. As seen in Table 2, the effective diameter of the polymer particle is nearly the same at two different salinities. The small change in size might be due to hydrogen bonding of water molecules to electron-rich oxygen atoms in the polymer chain causing the polymer to be slightly charged. The polymer coil is “relaxed (stretched)” in low salinity and “constrained” in high salinity. The apparent small reduction in size is conjectured to be driven by a reduced electrical double layer with ionic strength.


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2.1.5. Sintered Bead-pack. A quartz tube was filled with borosilicate glass beads of two different diameters of 1 mm and 250–300 µm (1:1 by volume ratio) and sintered in an oven at about 830 °C. Figure 3 shows a picture of an assembled bead-pack.

Figure 3. Photo of a sintered bead-pack with mixture of 1 mm and 250-300 µm borosilicate glass beads

The overall porosity of the sintered bead-pack was determined in an AccuPyc 1330 Pyconometer (Micromeritics Instrument Corporation) and double checked by an X-ray micro-CT scanned images and threshold processing using Otsu’s algorithm41. The porosity measured by pyconometer is 28.2±1.2% compared to 14 ACS Paragon Plus Environment

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28.6% obtained by thresholding micro-CT scan rendered image. A permeability of 54.73 Darcy for the bead-pack was measured experimentally by draining water from a hydrostatic column through the pack. At the conclusion of each flooding experiment, the bead-pack was cleaned by sequentially flushing the medium with isopropanol, toluene and isopropanol to restore wettability. After drying the bead pack overnight, the same pack was used for the next injection sequence. Thus, the pore structure of the porous medium was unaltered in the sequence of experiments. The cleaning procedure was chosen to make sure that the wettability of glass beads was the same for each run. This was confirmed by measuring water contact angle of 27 ± 3o on clean glass beads in air. After exposure to oil, and following the above-mentioned flushing steps and air drying, water contact angle (with respect to air) was measured to be 29 ± 3o, essentially restoring the contact angle to its original state.

2.2. Interfacial tension measurement The classical method of drop-shape analysis was used to calculate the interfacial tension of oil/brine, oil/polymeric nanofluid and oil/SDS solution.27 The measured interfacial tensions of oil/brine, oil/polymeric nanofluid and oil/SDS are 43 ± 2 mN m-1, 8.8 ± 0.3 mN m-1 and 8.7 ± 0.3 mN m-1 respectively. 15 ACS Paragon Plus Environment

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2.3. Oil/brine (nanofluid)/borosilicate glass plate three-phase contact angle measurement The pre-cleaned borosilicate glass substrates were placed in a transparent plastic cuvette filled with oil (without dye). The glass substrates were cleaned sequentially with isopropanol, toluene and isopropanol followed by air drying overnight. A sessile droplet of brine or nanofluid (0.3 ± 0.05 mL, with methylene blue dye) was placed on the glass substrate immersed in the oil with a Hamilton microsyringe (B-D needle, 25G 5/8). After placing the droplet on the solid substrate, the image of the droplet on the glass substrate was captured with a digital camera (Canon A720 IS) until the droplet stopped spreading. The static threephase contact angle for brine and nanofluid is 65±4o and 25±3o respectively. The advancing and receding contact angle was measured by the tilting plate method. Basically, after the deposited droplet stopped spreading on the solid substrate, we slowly tilted the sample until the sessile drop began to move in the downhill direction. The downhill contact angle is the advancing angle and the uphill angle the receding contact angle. The contact angle was calculated by image analysis (Image Pro, version 6). The measured brine advancing and receding contact angle is 88±2o and 42±3o and nanofluid advancing and receding contact 16 ACS Paragon Plus Environment

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angle is 25±3o and 22±3o. All of the experiments were conducted at a room temperature of 22 ± 1 °C.

2.4. Flooding experiments. 2.4.1. Experimental setup. The aim of the experiments was to compare and contrast the residual oil reduction with and without nanofluid as a function of capillary number (Ca). All of the flooding experiments were conducted at room temperature (22±1 oC). A schematic diagram of the experimental setup is presented in Figure 4.


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Figure 4. Schematic diagram of the experimental setup.

The experimental setup consisted of syringe pumps, pressure transducers, the bead-pack, stainless syringes and 1/8’’ (3.175 mm) PFA tubings. The syringe pumps (Harvard Apparatus) were operated at constant flow rate. The pump reproducibility is ±0.05%. Using a 20 mL stainless steel syringe, the pump’s minimum and the maximum flow rates are 52.86 nL/min and 54.89 mL/min respectively. The inlet and outlet of the bead-pack were connected to pressure transducers (accuracy class 0.1%, supplied by HBM) for measuring pressure drop across the bead-pack during the flooding experiments.

2.4.2. Flooding procedure The capillary number is proportional to the ratio of viscous flow induced pressure drop to capillary pressure. By definition, in this paper, the capillary number is Ca =

(1)

where is the fluid viscosity, is the superficial velocity, and is the interfacial tension between the aqueous phase and oil. Contact angle is not included in this definition, since the primary purpose is to delineate the effects of wettability alteration as discussed further below. We changed the pump flow rate to change 18 ACS Paragon Plus Environment

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the superficial velocity to realize different capillary numbers. During oil recovery, the displacing fluid is synonymous with brine (w is used as a subscript) and the displaced fluid is identified as oil (o is the subscript). The enhanced recovery experiment operates on a tertiary recovery mode as opposed to secondary enhanced recovery, meaning that a low Ca flow always precedes a high Ca flood. A preevacuated bead pack is filled with brine in order to avoid trapped air bubbles. Oil is then injected at a sufficiently high rate so that the capillary number is about 10-4. The primary purpose of injecting oil at this high rate is to reduce the zone of end-effect.42 The effluent brine and oil are collected, and thus the saturation of oil and brine are known. At this point, the bead pack is filled predominantly with oil except for residual brine saturation, , of 15–20%. For oil recovery experiments, we injected three to four pore volumes (PV) brine at Ca = 10-7 into the oil-filled bead pack to simulate secondary water-flooding. At the end of this step, no oil production was observed. The breakthrough point was observed at about 0.48–0.5 PV for the brine flooding (slightly change due to different runs). Since the fractional flow of oil is unity until this point, recovery could be computed from the injection rate, and is shown accordingly in the oil recovery figures. Before the breakthrough point, the volume of oil recovered has to be equal to the volume of brine injected according to volume conservation. Oil production and the pressure drop across the bead pack were recorded as a function 19 ACS Paragon Plus Environment

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of pore volumes. Thus, secondary water-flood residual oil saturation was established. The three steps of evacuation, oil intrusion and low capillary number water-flood were the same for each flooding experiment; results of which are presented below. Following water-flood, in the first experiment, nanofluid was injected at a Ca = 10-7 ranging from three to seven PV mimicking a tertiary recovery process. The process was however unusual because Ca was held to values typical of a secondary water-flood. Nanofluid injection was terminated when no discernible oil was evident in the outlet stream. Oil cut and pressure were recorded. As mentioned previously, at the conclusion of the flooding experiment at Ca = 10-7, the bead-pack was cleaned by flushing the medium with isopropanol, toluene and isopropanol, essentially restoring the contact angle to its original state. To delineate the effect of reduced capillarity from that of wettability (other than inevitable changes through dynamic contact angle), no surfactant was added in the brine for the high Ca tertiary brine displacement. Flow rate was used to set Ca. Through two different tertiary injections at the same Ca with and without the nanofluid, a distinction in the outcome would be indicative of the effect of the disjoining pressure on oil removal. Figure 5 presents a schematic sequence of the experimental procedure.


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Figure 5. Schematic sequence of the experimental procedure showing the flooding process.

The displacement efficiency was then evaluated and calculated based on = 1

(2)

where represents the oil saturation after brine injection at Ca = 10-7, and represents the residual oil saturation after tertiary brine or nanofluid injection, i.e., at high Ca.

2.5. Imaging technique 2.5.1. 3D Visualization using X-ray microtomography. A high-resolution X-ray microtomography (X-ray micro-CT) was used to determine oil and brine (nanofluid) distributions in the sintered bead pack before and after injecting nanofluid. The micro-CT system consists of an X-ray generator, a detector, a 21 ACS Paragon Plus Environment

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translation system, and a computer system that controls motions, data acquisition and reconstruction. Once the sample is brought to its position and the scanner is activated, the projections of the magnified object are captured by the image intensifier. When the source is active, the X-rays penetrate through the object and reach the image intensifier, which converts X-ray energy into a form of light that is captured by a digital camera. The digitized data are sent to the computer and turned into raw files that can be processed into images.43 The images are stored as a stack of virtual 2D slices (a total of 3142 slices). The sample is rotated 360o in the X-ray beam while the detector is providing attenuation views to the data acquisition computer. After the scan is complete, the 2D slices are reconstructed to 3D volume using VG studio Max 2.2. The standard scanning parameter parameters in our cases were: four frames per projection, exposure time one second, angle of rotation 360o, X-ray tube voltage 160 kV and current 65 µA.

2.5.2. Imaging procedures. Initially, the dry bead pack was scanned to obtain the overall porosity. After the core reached oil and brine saturation, it was scanned again to get initial oil and brine distribution. The flooding sequence was then followed by consecutive cycles of brine and nanofluid injection. The core was scanned before and after nanofluid injection to map the oil distribution in order to see the performance of nanofluid compared to that of brine. A digital camera 22 ACS Paragon Plus Environment

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(Canon PowerShot A720 IS) equipped with a 58 mm macro-lens was also used to take pictures from the side at the end of each PV flooding.

3. RESULTS AND DISCUSSION 3.1. Flooding Results for Different Flooding Scenarios. Figure 6(a) shows the oil recovery versus pore volume of fluid injected for secondary (waterflood) and EOR processes. From Figure 6(a), we observe that around 65% oil was displaced by brine. Oil production ceased at about one PV, but in order to standardize the procedure, we continued injection until three PV brine was injected. After brine injection, we continued with nanofluid injection as tertiary mode but at the same capillary number (Ca = 10-7). Interestingly, 14.6% of additional oil was recovered using nanofluid compared to 0% using brine at Ca = 10-7. Figure 6(b) shows the pressure drop across the porous medium during injection at Ca = 10-7. It was observed that the average pressure drop was almost constant during the brine injection and the value is close to zero since the permeability of the core is large and is approximately 55 D (Darcy). The pressure drop increased and is oscillatory when nanofluid was injected to the bead-pack. The viscosity of the polymeric nanofluid was 1.097 mPa s. Given that the viscosity of oil was about 18 times higher, one would expect a higher pressure when oil flow dominates within the porous medium. Our observations are counter to this. We find that the pressure 23 ACS Paragon Plus Environment

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drop is about 0.1 to 0.15 psi higher during nanofluid injection and about 20 lamellae in the flow line is sufficient to induce this pressure drop. Oscillations in pressure drop are coincident with oil recovery (compare Figures 6a and 6b). Interestingly, the pressure drop of 0.1 psi is retained (the reason for this 0.1 psi is not clear cut) even after oil lamellae in the tube are visually absent, although a slight decay is evident. The trapped oil ganglia inside the bead-pack started to break into disconnected oil blobs, and was continuously perturbed and displaced as we injected nanofluid. This will be clearer in Section 3.2 where micro-CT images highlight differences between brine and nanofluid flooding.

Figure 6. (a) Oil recovery vs. injected PV for brine and nanofluid secondary and tertiary injection at Ca = 10-7 and T = 22±1 oC; (b) Pressure drop across the beadpack during brine and nanofluid injection at Ca = 10-7 and T = 22±1 oC.


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As mentioned previously, the second set of experiments comprise a sequence of low and high capillary numbers, with the latter again being both brine and nanofluid. High capillary numbers were achieved by increasing the injection rate. The outcome of the second sets of experiments was expected to clearly delineate the difference between reduced capillarity without wettability change, and increased oil recovery including wettability change. Figure 7 shows oil recovery during EOR at Ca = 10-5 and Ca = 10-4. Additional oil due to nanofluid injection is 6.9% at Ca = 10- 5 and 2.4% at Ca = 10-4. This is a downward trend with respect to incremental oil production. But the interesting observation is that with respect to Ca, even the total oil produced showed a slight decrease to no change after tertiary injection of nanofluid. In Table 3 we have summarized the results of the flooding experiments.


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Figure 7. Oil recovery vs. injected PV and EOR process with nanofluid compared to brine at (a) Ca = 10-5 and (b) Ca = 10-4 at a temperature of 22±1 oC.

Table 3. Oil recovery at secondary process and EOR using nanofluid and brine vs. Ca at a temperature of 22±1 oC. Secondary process Oil recovery after 3

Tertiary process (EOR)

Oil recovery after

additional oil

nanofluid

compared with

flooding, %

brine, %

Oil recovery after

PV brine injection at brine flooding, %

Ca = 10 , % -7

65.0 ± 3

10-7

0

14.6 ± 1.5

14.6 ± 1.5

63.2 ± 2

10-5

9.1

16.0

6.9

62.2 ± 2

10-4

12.3

14.7

2.4

As seen from Table 3, oil recovery due to nanofluid tertiary recovery decreases compared to brine as we increase the capillary number contrary to intuitive expectation of improved oil displacement. It is in the limit of low Ca that the highest additional recovery of 14.6% was obtained. This is to be tempered by the fact that the enhanced brine flood also recovers extra oil, and therefore the residual 26 ACS Paragon Plus Environment

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oil at the onset of nanofluid flooding is lower than in the lower Ca floods. But even as a percentage, oil recovered by nanofluid with respect to oil left behind by brine, we see that enhancing Ca decreases efficacy. Similar results have been observed recently by other researchers9 showing that increasing silica nanofluid injection rate significantly decreases incremental oil recovery. In some cases, they observed that there was no incremental oil recovery. Their explanation is that increasing the injection rate might affect nanoparticle accumulation near the core inlet rather than flowing through the pore throat. They observed visually that nanoparticles’ ‘cake’ at core inlet was more noticeable at higher injection rate. The situation is different in our case. The bead pack is more porous than the core samples used in reference 9 (permeability is around 1000 times larger and porosity is around nearly twice); in addition, we don’t observe any aggregates at the inlet. The reason why nanofluid performs best at a low capillary number of 10-7 is that nanofluid requires time for a film to form as a consequence of structural disjoining pressure to perform; for example, it takes around nine hours for one PV of nanofluid flooding at Ca = 10-7, while it takes only around 30 seconds for one PV of nanofluid flooding at Ca = 10-4. From our previous experimental studies on dynamic spreading of nanofluids on solids24 and recent mechanistic study of oil detachment from glass substrate using nanofluid,27 the time-scale for structural 27 ACS Paragon Plus Environment

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disjoining pressure mechanism to operate must be taken into account since the inner contact line moves much slower than that of the outer contact line, the latter being driven by capillarity. In our case, the velocity of the inner contact line as measured is 0.032 mm/min and is 0.32 mm/min for the outer contact line. The apparent decrease in efficacy of nanofluid with increasing Ca is best understood by comparing advection and nanofilm-formation time-scales,

!

and

"

respectively. In order for the structural disjoining pressure to operate, the characteristic time for nanofluid advection inside the bead-pack should be much larger than that for nanofluid film formation, i.e.,

!

≫

".

For a bead-pack with

length $, porosity %, and superficial velocity , the characteristic time for nanofluid advection inside the bead pack is nanofluid film formation is

"

=

)

*+,

!

=

'(

. The characteristic time for

, where -. is bead diameter and /01 is inner

contact line velocity. Table 4 summarize the results.

Table 4. Characteristic time for nanofluid advection along the bead-pack and nanofluid film formation vs. Ca.

23 , min

10-7

363.70

24 , min 31.30

10

-5

3.64 28 ACS Paragon Plus Environment

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10-4

0.36

From Table 4, we see that only the lowest Ca = 10-7 has

!

≫

",

which also

corresponds to highest EOR by nanofluid compared with brine. In order to verify that nanofluid can perform better when it is in contact with the solid substrate and the oil for a longer time, two sets of flooding experiments were conducted. In the first set, we flooded the pack at Ca = 10-4 until oil production ceased, subsequent to which we decreased the capillary number to Ca = 10-7. With respect to pore volumes injected, Figure 8 shows an additional 4.1% oil removal. The time-scale of course is considerably larger than with the higher Ca.


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Figure 8. Oil recovery vs. injected PV and EOR process with nanofluid flooding at different capillary numbers.

Since the time-scale is of primary importance, in the Ca = 10-7 experiments post nanofluid flooding, the bead-pack was left in contact with the injected fluid, and the pump turned off (Ca = 0) for different periods (57 hours and ten days). This was followed by additional injection at Ca = 10-7. Figure 9 shows the resulting additional oil recovery of 3.2% (10 day soak-time) and 1.9% (57 hour soak-time).

Figure 9. Oil recovery vs. injected PV and EOR process with different nanofluid soak-times.


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These two sets of experiments further verify our structural disjoining pressure mechanism. Longer the time nanofluid was in contact with the solid substrate and the oil, better was the performance. Nanofluid can perform better at low capillary number and as effectively as brine flooding at higher capillary number. Similar experiments with soaking followed by displacement with brine or SDS (the same IFT as polymeric nanofluid) resulted in no additional recovery.

To exclude interfacial tension induced oil recovery from that due to nanofluid structural disjoining pressure, an additional experiment was conducted by flooding with 1.35 mM SDS solution (the same IFT as polymeric nanofluid) at Ca = 10-7 after brine injection at Ca = 10-7. Figure 10 shows that 14.6% of additional oil was recovered using nanofluid compared to 2% using SDS solution at Ca = 10-7. The additional oil 2% by SDS solution is purely due to the interfacial tension reduction. Since capillary number was kept the same, the role of the interfacial tension would be through an alteration in contact angle (glass/oil/aqueous three-phase contact angle changes from 115o to 155o). Compared to oil recovery by SDS solution, the additional oil by nanofluid is 12.6%, which is due to the structural disjoining pressure.


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Figure 10. Oil recovery vs. injected PV and EOR process with nanofluid compared to 1.35 mM SDS solution at Ca = 10-7 at a temperature of 22±1 oC.

3.2. Oil and Brine Distribution Using X-ray micro-CT. Figure 11(a) shows the side views from the digital camera. The porous medium is predominantly filled with oil when brine was displaced by oil. The oil saturation was between 80-85%. After 3 PV of brine flooding at Ca = 10-7, we see that the gravitational effect is quite noticeable and oil was mostly displaced from the bottom and is retained towards the top. This apparently gravity induced entrapped oil was displaced (although incompletely) when injection was switched to nanofluid at Ca = 10-7. 32 ACS Paragon Plus Environment

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Figure 11(b) shows 3D images taken from X-ray micro-CT. In the 3D view, it is easier to see that gravity played an important role during brine flooding, although at a Ca = 10-7 one would expect capillarity to dominate over gravity. Nanofluid caused an apparent reduction in the gravitational effect during flooding process and oil was more uniformly displaced along the porous medium. The density of nanofluid is substantially the same as that of brine, but the interfacial tension with respect to oil is considerably smaller. Therefore, one would expect capillarity to dominate gravity for brine in comparison to nanofluid. The results are however quite contrary and it is useful to consider the Bond number. Since the only variable not considered thus far is the contact angle, we analyze its effect through Bond number Bo =

789:

;

,

(3)

during where Δ@ is the density difference between brine and oil, A is the gravitational acceleration, B is the bead radius, is the interfacial tension between aqueous phase and oil and CD is the advancing contact angle. The calculated Bo for brine is 0.119 compared to that of 0.022 for nanofluid. Clearly gravity may not be neglected during brine advance, but plays a negligible role during nanofluid injection. Even with an advancing contact angle of 88o, Ca is still sufficiently small for ensuring oil trapping. The receding contact angle for brine is 42±3o, indicative of water wetness. 33 ACS Paragon Plus Environment

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Video Clip 1 (see the supplementary material) depicts oil (red) and brine (light blue) distribution after 3 PV brine flooding at Ca = 10-7 and Video Clip 2 (see the supplementary material) shows oil and brine distribution after 3 PV nanofluid flooding at Ca = 10-7.

Figure 11. Visualization of oil and brine distribution inside bead pack after brine and nanofluid flooding (Ca = 10-7). (a) Side view from the digital camera and (b) 3D view from X-ray micro-CT; red is oil and light blue is aqueous phase.


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Figure 12 presents trapped oil ganglia (or blobs) before and after 3 PV nanofluid flooding. After 3 PV brine flooding, oil blobs are in large clusters and predominantly on the upper part of the porous medium. Nanofluid flooding breaks the large structures into small disconnected oil blobs of a few bead lengths.

Figure 12. Oil blobs before and after 3 PV nanofluid flooding at Ca = 10-7.

4. CONCLUSIONS In this work, a series of flooding experiments on EOR using nanofluid at different capillary numbers (Ca = 10-7, 10-5, 10-4) were performed and compared with brine after secondary flooding at a Ca = 10-7. Additional oil recovery of around 15% may be achieved by the nanofluid compared to brine at a Ca = 10-7. 35 ACS Paragon Plus Environment

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The additional oil recovery due to nanofluid decreases as we increase the capillary number due to two reasons: (i) there is less oil to be recovered because of mobilization due to enhanced Ca brine flooding and (ii) insufficient time for nanofluid film to advance through structural disjoining pressure and displace oil. Allowing the bead-pack to be treated with nanofluid and then displacing oil confirms that the second hypothesis is true. Improved oil recovery due to nanofluid is effective when

!

≫

".

To separate the interfacial tension induced oil recovery from that due to wettability alteration by structural disjoining pressure, a flooding experiment with SDS solution (the same IFT as polymeric nanofluid) was conducted at Ca = 10-7 after brine injection at Ca = 10-7. Compared to oil recovery by SDS solution, the additional oil by nanofluid is 12.6% and is due to the structural disjoining pressure. High-resolution X-ray microtomography 3D views showed that gravity played a more pronounced role during brine injection compared to nanofluid injection and was initially unexpected. It appears that this was primarily driven by reduced capillarity during brine advance. Nanonfluids are as effective as or better than high Ca brine flooding. Allowing nanofluid sufficient contact time appears to be the most effective for total oil recovered. Our findings in this study are expected to promote the understanding of EOR by nanofluids. 36 ACS Paragon Plus Environment

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ACKNOWLEDGMENTS This research is supported by Schlumberger-Doll Research Center. One of the authors, H.Z., wishes to thank Schlumberger for support through an internship. Assistance from Raji Shankar and Albert Perez Jr is much appreciated.

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Enhanced Oil Recovery Driven by Nanofilm Structural Disjoining

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