Improved Mobility of Magnetite Nanoparticles at High Salinity with

Feb 18, 2016 - When nMag (2500 mg/L) was introduced into Ottawa sand, 97% of the injected mass ... which increased nMag mobility 2-fold (78% effluent ...
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Improved Mobility of Magnetite Nanoparticles at High Salinity with Polymers and Surfactants Anthony A. Kmetz,†,§ Matthew D. Becker,†,∇ Bonnie A. Lyon,† Edward Foster,‡ Zheng Xue,‡ Keith P. Johnston,‡ Linda M. Abriola,† and Kurt D. Pennell*,† †

Department of Civil and Environmental Engineering, Tufts University, Medford, Massachusetts 02155, United States McKetta Department of Chemical Engineering, The University of Texas at Austin, Austin, Texas 78712, United States

‡

S Supporting Information *

ABSTRACT: Engineered nanoparticles have been proposed for use as contrast agents to enhance geophysical characterization of oil and gas reservoirs. Under saline conditions and in the presence of fine materials, nanoparticle mobility in porous media can be severely limited. To address this issue, a series of column experiments was performed to evaluate the ability of selected polymers and surfactants to enhance the transport of magnetite nanoparticles (nMag) coated with cross-linked polymers in the presence of American Petroleum Institute (API) brine (8 wt % NaCl + 2 wt % CaCl2). Aqueous suspensions containing nMag and API brine were injected at pore-water velocities of 2 ± 0.04 m/day or 10 ± 0.40 m/day through columns packed with either 40−50 mesh Ottawa sand or 60−170 mesh crushed Berea sandstone. When nMag (2500 mg/L) was introduced into Ottawa sand, 97% of the injected mass was recovered in the column effluent, indicating high mobility under saline conditions. However, the injection of nMag (2500 mg/L) into crushed Berea sandstone resulted in >60% nMag retention within the column. In order to improve delivery, nMag (2500 mg/L) was co-injected with 1000 mg/L hydroxyethyl cellulose (HEC-10), which increased nMag mobility 2-fold (78% effluent recovery). Co-injection of nMag with 1000 mg/L Gum Arabic or Calfax 16L-35, an anionic surfactant, resulted in slightly lower effluent recoveries of 72% and 69%, respectively. A preflood with 1000 mg/L HEC-10, followed by the injection of nMag alone (2500 mg/L), yielded an additional 20% improvement in nMag mobility (93% effluent recovery), suggesting that HEC-10 screened nMag attachment sites. A multisite nanoparticle transport model that accounts for heterogeneous mineralogy with variable attachment kinetics was able to accurately reproduce the effluent concentration data. Coupled with the observed 7-fold reduction in maximum retention capacity, the model parameter fits provide further evidence to support a site-blocking mechanism. These findings demonstrate the potential for relatively small additions (0.1%) of commercially available polymers and surfactants to greatly improve nMag mobility in porous media.

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unanticipated water breakthrough in production wells.4,5 Injection of nanoscale contrast agents, such as superparamagnetic magnetite nanoparticles (nMag), could be deployed in cross-well electromagnetic tomography or magnetomotive acoustic imaging to characterize reservoir flow and saturation regimes at intermediate length scales.6,7 Understanding the nature and magnitude of porous media− nanoparticle interactions and their impacts on transport processes in the subsurface environment will be vital to the successful deployment of nanoparticles for such interwell applications. Furthermore, an understanding of nanoparticle mobility is also of interest for enhanced oil recovery applications with nanoparticle-stabilized emulsions and foams.8,9 The synthesis of nanoparticles that exhibit stability against precipitation, mobility, and high magnetic susceptibility under saline conditions remains a challenge.10,11 Several research groups have conducted column studies to assess nMag mobility in quartz sands and intact cores under saline conditions. Xue et al.12 evaluated the ability of a copolymer coating, which consisted of poly(2-acrylamido-2-methyl-1-propanesulfonic

INTRODUCTION The development of engineered nanoparticles that can detect, image, or modify reservoir conditions could greatly improve oil and gas recovery. The unique properties that emerge at the nanoscale enable new approaches for subsurface characterization and reservoir control. For example, injection of highly mobile, magnetically susceptible nanoparticles could enhance our ability to spatially resolve fractures, highly transmissive media, and low-permeability zones. This information could then be used to improve reservoir management during secondary or tertiary oil and gas production, which is critical for sustained production, since average oil recovery rates in mature fields typically range from 20% to 40%.1,2 A measurement gap in subsurface characterization scales currently exists between the interwell space interrogated by tracers, and near-well data derived from geophysical logging and core analysis. For example, traditional geophysical logging tools provide high-resolution data in the immediate vicinity of a bore-hole, but geological interpretation and computer models are needed to extrapolate data to the macroscale. On the other hand, interwell tracer tests have been successfully deployed over distances of ≥2 km, with breakthrough times ranging from 8 to 61 days.3 However, uncertainty in the presence and distribution of highly transmissive zones at the intermediate scale (e.g., 10−100 m from the wellbore) can result in © XXXX American Chemical Society

Received: August 5, 2015 Revised: February 3, 2016

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DOI: 10.1021/acs.energyfuels.5b01785 Energy Fuels XXXX, XXX, XXX−XXX

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the stability of nanoparticle suspensions,27,28 which may further aid mobility. The goal of this research was to evaluate the ability of selected polymers and surfactants, to improve the mobility of iron oxide nanoparticles (nMag) coated with tetraethyl orthosilicate, 3-aminopropyl triethoxysilane, and poly(2-acrylamido-2-methyl-1-propanesulfonic acid-co-acrylic acid) (TEOSAMPS-co-AA), under saline conditions in natural porous media. Batch experiments were performed using 11 commercially available polymers and surfactants to assess stability in saline solutions and to determine relevant physicochemical properties. Based on batch tests, Calfax 16L-35, Gum Arabic, and hydroxyethyl cellulose (HEC-10) were selected and evaluated for their ability to enhance the mobility of nMag in columns packed with unwashed 40−50 mesh Ottawa sand or crushed Berea sandstone and saturated with API brine. A multiconstituent nanoparticle transport model26 was employed to simulate effluent column data and quantify nMag attachment rates and maximum retention capacities in the presence and absence of stabilizing agents. The experimental and modeling results of this study provide proof of concept for the application of chemical additives to enhance nMag mobility and facilitate comparisons of the performance of preflood and co-injection amendment delivery and assessment of the mechanism contributing to enhanced nMag mobility.

acid-co-acrylic acid) or poly(AMPS-co-AA), to improve the stability and transport of nMag at high salinities. The AA anchor groups are grafted to amine-functionalized nanoparticles via amide linkages.8,13 The AMPS groups are strongly acidic and bind very weakly to Ca2+ cations, such that they remain solvated in American Petroleum Institute (API) brine (8 wt % NaCl + 2 wt % CaCl2; ionic strength (I) = 1.9 M) up to 120 °C. For an AMPS:AA ratio of 1:1 or higher, the co-polymer is solvated in API brine, such that the extended chains on the surface provide electrosteric stabilization against nanoparticle aggregation, and also weaken the interactions with silica and crushed sandstone surfaces. In 40−50 mesh Ottawa sand saturated with API brine, for example, 91% of the injected nMag mass was recovered in the column effluent at an AMPS:AA ratio of 1:1, and the recovery increased to 96% when the AMPS:AA ratio was increased to 3:1.12 Yu et al.14 investigated the performance of seven different polymer coatings on nMag transport through intact Boise sandstone cores. When deionized (DI) water was used as the mobile phase, >95% of the applied nMag passed through the Boise cores; however, nMag mobility decreased substantially in the presence of 1 wt % NaCl, with up to 58% of the applied nMag mass being retained. In the case of poly(acrylic acid)− poly(butyl acrylate)-coated nMag, retention increased more than 2-fold (from 21% to 54% of the applied mass) when the salinity was increased from 1 wt % NaCl to API brine.14 These studies illustrate the substantial impact of saline conditions and surface coating properties on nMag suspension stability and mobility in porous media. The first reported attempt to utilize nanoparticles in a reservoir occurred in 2010, when Saudi Aramco performed a push−pull test using A-Dots (carbon-based fluorescent nanoparticles) in the Arab D formation of the Ghawar field.15 With a lateral reach of ∼20 ft from the borehole, the nanoparticles were injected and held for 72 h before being extracted, recovering ∼90% of the injected mass.15 In a subsequent interwell test, A-Dots mixed with filtered seawater (I ≈ 0.7M) were detected in a recovery well ∼500 m from the point of injection.16 While mobility of the A-Dot suspension was demonstrated, achieving stability and mobility-functionalized nanoparticles in heterogeneous domains at high salinity represent major technical challenges that must be overcome before the potential benefits of down-hole nanoparticle injection can be realized.9,17,18 One possible approach to improve nanoparticle performance at relatively low cost is the addition of stabilizing agents, which could either be applied as a preflood or co-injected with the nanoscale contrast agent. Polymers and surfactants have been employed in both the environmental remediation and petroleum industries to alter viscosity, improve sweep efficiency, and enhance the recovery of organic liquids (e.g., oil or chlorinated solvents) from various geological formations.19−23 In most subsurface formations, surfactants strongly adsorb onto mineral surfaces and exhibit a limiting (maximum) adsorption capacity that can be described by the Langmuir model.20,24,25 Recently, Becker et al.26 demonstrated that poly(acrylic acid)−octylamine (PAA-OA), present at residual levels in quantum dot nanoparticle suspensions, preferentially adsorbed onto quartz sand, which resulted in reduced quantum dot attachment near the column inlet. Thus, adsorption of surfactants or polymers can act to block potential nanoparticle attachment sites, facilitating improved nanoparticle mobility. In addition, polymers and surfactants have been shown to improve

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MATERIALS AND METHODS

Nanoparticles. Magnetite nanoparticles were synthesized using a modification of procedures described by Xue et al.12 Briefly, citratestabilized iron oxide nanoparticle clusters were coated with TEOS (Sigma−Aldrich, St. Louis, MO), 3-aminopropyl triethoxysilane (APTES) (Sigma−Aldrich, St. Louis, MO), and poly(AMPS-co-AA), which was synthesized from potassium persulfate (Acros Organics, Geel, Belgium), sodium metabisulfite (Alfa Aesar, Ward Hill, MA), 2acrylamido-2-methyl-1-propanesulfonic acid (Sigma−Aldrich, St. Louis, MO), and acrylic acid (Alfa Aesar, Ward Hill, MA). The poly(AMPS-co-AA) coating was grafted onto the nanoparticles at a poly(AMPS:AA) ratio of 3:1. The earlier grafting procedure8 was modified by first adding a thin layer of silica with TEOS and then adding amines in the second step with APTES.29,30 In this approach, the amines are added more uniformly than in the case of APTES addition directly on iron oxide,8 resulting in more uniform polymer grafting. The TEOS AMPs-co-AA-coated iron oxide nanoparticles had a mean hydrodynamic diameter of 150 nm and a zeta potential of −47 mV at pH 5, while the organic content was 37%, based on thermogravimetric analysis (TGA). During the initial hydrolysis, aggregates of magnetite particles are formed where the primary particle size is on the order of 10 nm, as is very common for this type of synthesis.31 The thickness of the silica layer on the magnetite particles is on the order of 10 nm thick. The degree of aggregation increases further during the polymer grafting step, such that the final clusters are on the order of 150 nm.31 A representative transmission electron microscopy (TEM) image of the TEOS AMPs-co-AA-coated iron oxide nanoparticles is shown in Figure S1 in the Supporting Information. In addition, TEM and scanning electron microscopy (SEM) with energy-dispersive X-ray spectroscopy (EDS) mapping were used to confirm the presence of iron in deposited nanoparticles (see Figures S2 and S3 in the Supporting Information). Polymers and Surfactants. Eleven (11) polymers and surfactants were evaluated as potential agents to enhance nMag mobility. Gum Arabic and HEC-10 were purchased from Sigma−Aldrich (St. Louis, MO). Gum Arabic, which is commonly used in the food industry as a stabilizing agent and emulsifier,32 is derived from the acacia tree and consists of a mixture of glycoproteins and polysaccharides with a beige powdery appearance. HEC-10 is used as a viscosity modifier and stabilization agent in a variety of industries ranging from beauty products to oil and gas production, and it has a white powdery B

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Energy & Fuels appearance. Calfax 16L-35 consists of sodium hexadecyl diphenyl oxide disulfonate and was obtained from the Pilot Chemical Company (Cincinnati, OH). Amphosol 810B, Petrostep SB, Stepantan AS-12 46, and Steol CS-330 were provided by the Stepan Company (Northfield, IL). Amphosol 810B is a mild amphoteric surfactant derived from caprylate and caprate methyl esters. Petrostep SB is a cocamidopropyl hydroxysultaine used as a premium foaming agent and exhibits superior foaming in high electrolyte solutions. Stepantan AS-12 46 is an aqueous solution of sodium α-olefin sulfonate that can be used as a drilling foam base, in fire-fighting foam applications, and in other foam-forming products. Steol CS-330 is a sodium lauryl ether sulfate derived from fatty alcohols with good foaming and viscosity characteristics for use in shampoo and hand soaps. Sodium dodecyl sulfate (SDS) is used as a wetting agent that is effective in both acidic and alkaline conditions, and was purchased from Fisher Scientific (Waltham, MA). Aerosol AY-100 and Aerosol MA-80, which were purchased from Cytec Industries, Inc. (West Paterson, NJ), are anionic surfactants that exhibit high electrolyte tolerance and are used as surface tension depressants. Rhodacal DS-10 (Sanofi USA, Bridgewater, NJ) is a sodium dodecylbenzenesulfonate that is used as a costeffective wetting agent. Batch stability tests were conducted at room temperature (23 ± 1 °C) by adding each polymer or surfactant, at concentrations ranging from 100 mg/L to 5000 mg/L, to API brine in glass vials, which were then mixed at 250 rpm for 48 h (Innova 2100, New Brunswick Scientific Co., Inc., Edison, NJ) and allowed to stand for 24 h. Porous Media. The 40−50 mesh size fraction of Ottawa sand was obtained by sieving 2-lb increments of F-50 Ottawa Sand (U.S. Silica, Berkeley Springs, WV) for 10 min cycles with a Model RX-29 Ro-Tap sieve shaker (W.S. Tyler, Inc., Mentor, OH). After each cycle, the desired fraction was retained and the process was repeated for at least 3 cycles or until ≥95% weight was retained on the 50-mesh screen. The d10 and d50 values of the 40−50 mesh size Ottawa sand were 320 and 335 μm, respectively, and the specific surface area (SSA) was 0.013 m2/g.33,34 The 60−170 mesh size fraction of Berea sandstone was obtained from a block of Berea 400 sandstone (Cleveland Quarries, Vermilion, OH) that was crushed and sieved by StimLab, Inc. (Duncan, OK). The d10 and d50 grain diameters of the crushed Berea sandstone were 111 and 154 μm, respectively, and the specific surface area (SSA) was 22.54 m2/g.25 To provide conditions that were more representative of field scenarios, all experiments were performed with unwashed and unaltered porous media (i.e., no rinsing, acidwashing, or baking). X-ray diffraction (XRD) analysis of Ottawa sand indicated a silica content of >99%.35 XRD analysis of the Berea sandstone indicated a quartz content of 83%−88% and a clay content of 5%−7%, including illite, chlorite, and kaolinite. Column Studies. Mobility experiments were performed in borosilicate glass columns (2.5 cm (diameter) × 10.5 cm (length), Kontes, Vineland, NJ) that were packed in 1 cm increments, vibrated, and tamped with a rod and disk (2.5 cm in diameter). Polytetrafluoroethylene (PTFE) end plates were fitted with a 40-mesh nylon screen and a 70 μm nylon filter (Spectrum Laboratories, Inc., Rancho Dominguez, CA) to distribute flow at the inlet and avoid any loss of fines. To promote the dissolution of any entrapped gas, dry-packed columns were purged with CO2 gas for at least 20 min. The columns were then saturated with at least 10 pore volumes (PVs) of API brine (8 wt % NaCl + 2 wt % CaCl2, I = 1.9 M) that was prepared in degassed DI water and delivered in the up-flow direction using a Dynamax SD-200 pump (Varian, Inc., Palo Alto, CA) equipped with a 25 mL pump head and dampener. The mean porosity of the packed columns was 37.1% ± 0.26% for Ottawa sand and 43.0% ± 0.20% for crushed Berea sandstone. The permeabilities of Ottawa sand and crushed Berea sandstone were determined to be 8720 mD (8.61 × 10−12 m2) and 543 mD (5.40 × 10−13 m2), respectively, based on a constant head permeameter test conducted in accordance with American Society for Testing and Materials (ASTM) Method D2434-68.36 After the column was completely saturated with API brine, ∼3 PVs of a nonreactive tracer (2.0 M NaBr), followed by ∼3 PVs of API brine, were injected in the up-flow direction using a syringe and Model 22 syringe pump

(Harvard Apparatus, Inc., Holliston, MA) to determine the hydrodynamic dispersion coefficient and assess water flow through each packed column. Effluent tracer samples were collected in 15 mL sterile plastic centrifuge tubes (VWR International, Radnor, PA) with a CF-2 SpectraChrom fraction collector (Spectrum Laboratories, Inc., Rancho Dominguez, CA). Stable nMag suspensions were prepared in an Erlenmeyer flask with a magnetic stir bar by diluting a concentrated nMag stock suspension in API brine to achieve the desired input concentration. Suspensions were prepared at two nominal concentrations625 mg/L (632−633 mg/L) or 2500 mg/L (2439−2529 mg/L) as Fe3O4and were adjusted to pH 7 ± 0.1 using 1.0 M NaOH from Sigma−Aldrich (St. Louis, MO). Once prepared, the nMag suspensions were injected into the packed columns, and effluent samples were collected following the same procedures used for the nonreactive tracer test. For experiments in which amending agents were co-injected with nMag, the respective agents were added to the influent nMag suspension. The pore-water velocities used for the experiments were based on a fast-flow scenario (10 m/day) and a slow-flow scenario (2 m/day), with the latter being on the upper limit of reservoir pore-water velocities.37 Solid-phase samples were collected from selected column experiments to allow for the imaging of deposited nMag. Analytical Methods. Aqueous phase concentrations of nMag were determined by ultraviolet−visible absorbance spectroscopy using a Shimadzu UV-1800 (Shimadzu Corporation, Kyoto, Japan) operated at a wavelength of 600 nm. Accuracy of the UV method was confirmed through analysis of nine duplicate samples that were prepared using a Discover SP-D microwave digester (CEM Corporation, Matthews, NC) with concentrated nitric acid, followed by quantification of total iron using inductively coupled plasma−optical emission spectrometry (ICP-OES) (Model Optima 7300 DV, PerkinElmer, Waltham, MA). The cumulants mean hydrodynamic diameter (i.e., Z-average) of nMag was determined by dynamic light scattering (DLS), using a Zetasizer Nano ZS analyzer (Malvern Instruments, Ltd., Southborough, MA), operated in a noninvasive backscattering mode at an angle of 173°. Prior to use, the ZetaSizer was calibrated using monodisperse polystyrene spheres (Nanosphere Size Standards, Duke Scientific, Palo Alto, CA) with a mean diameter of 97 ± 3 nm and a zeta potential transfer standard (Malvern Instruments, Ltd.) with a mean zeta potential of −68 ± 6.8 mV. Approximately 1 mL of nMag suspension (625 or 2500 mg/L) was transferred into a disposable cuvette (Malvern Instruments, Ltd.) and analyzed using a green laser at a wavelength of 532 nm. The viscosity of selected amending agents was measured in triplicate over a concentration range of 50−2000 mg/ L of active ingredient in API brine, using a Brookfield DVII Viscometer (Brookfield Engineering Laboratories, Inc., Middleboro, MA) operated at shear rate of 200 1/s. Samples were prepared for TEM imaging by drop-casting 5 μL of an nMag suspension (2500 mg/ L in deionized water) onto a lacey carbon on 300 mesh copper TEM grid. EDS mapping was performed using a JEOL 2010 TEM in annular dark field scanning TEM (STEM) mode, operated at 200 kV. SEM samples were prepared by collecting media on conductive doublesided carbon tape attached to an aluminum stub mount (Electron Microscopy Sciences, Hatfield, PA). The samples were then air-dried overnight and imaged with a Zeiss Supra55 variable pressure fieldemission SEM system (Carl Zeiss Microscopy, Peabody, MA), operated under high vacuum with an SE2 detector and beam voltage of 3 kV. The presence of iron oxide nanoparticles in SEM samples was confirmed using an EDS detector that was attached to the SEM system and analyzing for iron content in bare versus attached nanoparticle regions with the spectrum function. Elevated iron concentrations were observed in regions of attached nanoparticles, compared to that observed in nanoparticle-free sand (e.g., 2.4 wt % Fe vs 0.75 wt % Fe, respectively), as shown in Figure S3 in the Supporting Information. Column effluent tracer samples were diluted by a factor of 50 with DI water and measured using a bromide probe (Cole−Parmer North America, Vernon Hills, IL). A five-point standard curve ranging from 0.02 M NaBr to 2.0 M NaBr was also diluted 50-fold, measured with the bromide probe, and used to quantify bromide in effluent tracer samples. C

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Energy & Fuels Mathematical Modeling. A one-dimensional (1D) nanoparticle transport model with modified first-order deposition kinetics was used to describe the transport and deposition of nMag in porous media saturated with API brine:34,38−40

ρ ∂S ∂C ∂ 2C ∂C + b = DH 2 − vp ∂t θw ∂t ∂x ∂x

Table 1. Stability (Absence of Precipitation or Emulsion Formation) of Selected Polymers and Surfactants in API Brine (8 wt % NaCl + 2 wt % CaCl2) at Active Ingredient Concentrations of up to 5000 mg/L

(1)

trade name

where C is the concentration of nMag in solution, t the time, ρb the bulk density of the porous media, θw the volumetric water content, S the concentration of nMag attached to the solid phase, DH the hydrodynamic dispersion coefficient, x the distance along the column axis, and vp the pore-water velocity. To account for the varying attachment capacities that may exist in the highly heterogeneous crushed sandstone media, a two-site model was employed to describe solid-phase deposition of nMag particles:

ρb ∂S ρ ∂S ρ ∂S = b 1 + b 2 = katt,1ΨC + katt,2C θw ∂t θw ∂t θw ∂t

Amphosol 810B CALFAX 16L-35 Gum Arabic HEC-10 Petrostep SB Steol CS-330 Stepantan AS-12 46 Aerosol AY-100 Aerosol MA-80 Rhodacal DS-10

(2)

where Si is the solid phase concentration of nMag on site i, and katt,i is the attachment rate of site i. In the case of site 1, the first-order deposition rate (katt,1) is scaled by a Langmuir-type blocking function (Ψ) that accounts for saturation of nMag deposition sites on the solid surface, which is a commonly observed phenomenon in nanoparticle transport through watersaturated porous media.40−43 Ψ is a function of space and time, changing as the attached concentration approaches Smax,1, which is the maximum capacity for nMag retention on site 1:44 Ψ=

SDS

capramidopropyl betaine sodium hexadecyl diphenyl oxide disulfonate exudates of acacia senegal and seyal trees hydroxyethyl cellulose sulfo betaine sodium laureth sulfate sodium alpha olefin sulfonate sodium diamyl sulfosuccinate sodium dihexyl sulfosuccinate sodium dodecylbenzenesulfonate sodium dodecyl sulfate

stability in API brine up to 5000 mg/L up to 5000 mg/L up to 5000 mg/L up up up up up up no

to to to to to to

5000 5000 5000 5000 2000 1000

mg/L mg/L mg/L mg/L mg/L mg/L

no

water and API brine were determined to be 1.2 × 10−3 ± 2.0 × 10−5 Pa s and 1.4 × 10−3 ± 4.2 × 10−5 Pa s, respectively, at 23 ± 1 °C (Figure 1), which is consistent with previous measurements of water and brine viscosities at this temperature.49,50 At active ingredient concentrations of up to 2000 mg/L, the viscosities of Amphosol 810B, Calfax 16L-35, Gum Arabic, Petrostep SB, Stepantan AS-12 46 in API brine were 0.09). In contrast, the viscosity of API brine amended with HEC-10 increased exponentially above an active ingredient concentration of 100 mg/L, reaching a viscosity of 5.0 × 10−3 Pa s at a HEC-10 concentration of 1600 mg/L. Similarly, the viscosity of API brine and Steol CS-330 increased exponentially above concentrations of 1000 mg/L, reaching a value of 2.3 × 10−3 Pa s at 2000 mg/L. For subsequent nMag transport experiments, HEC-10 was selected to represent viscous polymers that are used to control sweep efficiency, Calfax 16L-35 was selected as a representative anionic surfactant that exhibited low viscosity and stability in API brine, and Gum Arabic was selected as a representative low-cost, food-grade stabilizing agent. nMag Mobility in Ottawa Sand. A set of three column studies was performed to evaluate the transport of nMag through columns packed with 40−50 mesh Ottawa sand saturated with API brine. At a pore-water velocity of vp = 2 m/ day, pulse injections (3 PVs) of nMag (625 mg/L or 2500 mg/ L) and API brine into 40−50 mesh Ottawa sand resulted in 80% and 97% mass recovery in the column effluent, respectively (see Figure 2A, as well as Table 2). The greater mass breakthrough observed with increasing applied concentration is consistent with a limiting or maximum retention capacity (Smax,1), which has been reported for other nanoparticles such as fullerene aggregates (nC60, mean diameter = 90 nm).34,42 The nanoparticle transport model (eqs 1−3) was used to simulate the nMag effluent concentration data shown in Figure 2A. The fines content of 40−50 mesh Ottawa sand is minimal;51 thus, it was assumed that all solid-phase attachment sites exhibited a limited retention capacity and katt,2 was set to zero. The fitted, single-site, nanoparticle transport model was able to reproduce most of the features in the nMag effluent

Smax,1 − S1 Smax,1

chemical name

(3)

This blocking function term scales the effective first-order nMag deposition rate with the amount of nMag deposition on the solid surface; deposition approaches zero as S1 approaches Smax,1. Two-site deposition models are traditionally invoked to simulate colloid and nanoparticle deposition to a heterogeneous solid-phase surface.26,45−48 In the present work, the two-site model was implemented under the assumption that the heterogeneous nature of the crushed Berea sandstone promotes particle attachment to different regions of the porous media surface at different kinetic rates. It was further assumed that only one class of retention sites (site 1) exhibits a limiting capacity over the time scales examined in this study. Thus, site 2 was treated as having a much larger retention capacity, consistent with fine materials present in the porous medium. Equations 1−3 were solved with an implicit-in-time and central-in-space finite difference scheme implemented in the MATLAB R2010a program (The Mathworks, Inc., Natick, MA). The pore-water velocity (vp) was determined from the liquid mass collected in the effluent vials over a given time and the measured porosity of each column. Hydrodynamic dispersion (DH) was independently determined from tracer data in each column experiment using the CFITIM3 model in STANMOD, Version 2.08.1130 (USDA Salinity Lab, Riverside, CA). Values for katt,1, katt,2, and Smax,1 were estimated by fitting the model shown in eqs 1−3 to effluent breakthrough data, using a nonlinear least-squares minimization algorithm.26

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RESULTS AND DISCUSSION Polymer and Surfactant Screening. Batch screening tests were performed to determine the stability (e.g., precipitation or emulsion formation) of the selected polymers and surfactants in API brine, as a function of active ingredient concentration (Table 1). Amphosol 810B, Calfax 16L-35, Gum Arabic, HEC10, Petrostep SB, Steol CS-330, and Stepantan AS-12 46 were all stable in API brine at amending agent concentrations up to 5000 mg/L. In contrast, SDS, Aerosol AY-100, Aerosol MA-80, and Rhodacal DS-10 were not stable in API brine at active ingredient concentrations above 1000 mg/L, and thus, were eliminated from further consideration. The viscosities of DI D

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Figure 1. Change in dynamic viscosity as a function of chemical additive concentration at 23 ± 1 °C. All solutions were prepared in API brine (8 wt % NaCl + 2 wt % CaCl2) adjusted to pH 7.0.

(see Figure 2A and Table 2). However, the model simulation of the 625 mg/L nMag pulse injection rose to a plateau concentration more rapidly than the experimental data, indicating that nanoparticle deposition was still occurring. This discrepancy may be the result of a secondary kinetic deposition process, which was not considered in the one-site Smax model. To further demonstrate the applicability of the nanoparticle transport model, and to confirm that nMag deposition kinetic parameters were not sensitive to mass loading, the fitted parameters obtained for the 625 mg/L pulse injection were used to predict nMag transport in Ottawa sand for the pulse injection concentration of 2500 mg/L (Figure 2A). The injection of a more concentrated nMag suspension (i.e., greater mass loading) resulted in more rapid saturation of the available attachment sites on the Ottawa sand, which led to earlier nMag breakthrough and greater mass recovery in the column effluent. The close agreement between these model predictions and experimental data suggests that katt,1 and Smax,1 are not dependent on the applied mass loading for the injection concentration range considered here. To further explore the effect of the model simulations on the fitted parameters, the values of katt,1 and Smax were varied 5-fold for the 2500 mg/L pulse injection. As shown in Figure S4 in the Supporting Information, a 5-fold increase in katt,1 (from 26.64/day to 133.2/day) had a minimal effect on the shape of the nMag breakthrough curve (i.e., slight sharpening of the front), whereas a similar change in the Smax parameter (from 0.066 mg/g to 0.33 mg/g) resulted in delayed nMag breakthrough and a gradual approach to the concentration plateau. Because of the relatively high mobility of nMag in 40−50 mesh Ottawa sand at an injection concentration of 2500 mg/L (97% mass breakthrough), only incremental improvements in mobility would be possible, following the addition of a stabilizing agent. Thus, co-injection of a polymer with the nMag suspension was performed at the lower applied nMag concentration (625 mg/L), where lower mobility was observed. Co-injection of 1000 mg/L Gum Arabic +100 mg/L HEC-10

Figure 2. Measured and simulated effluent breakthrough curves obtained for pulse injections of nMag (625 and 2500 mg/L in API brine) alone or co-injected with a chemical additive in (A) 40−50 mesh Ottawa sand and (B) 60−170 mesh crushed Berea sandstone at a nominal pore-water velocity of vp = 2 m/day. The dashed line corresponds to a representative nonreactive tracer test; experimental conditions for each breakthrough curve and fitted model parameters are given in Table 2.

breakthrough curve data, yielding values of katt,1 = 54.96/day and Smax,1 = 0.072 mg/g for the 625 mg/L nMag pulse injection E

DOI: 10.1021/acs.energyfuels.5b01785 Energy Fuels XXXX, XXX, XXX−XXX

2.85 3.03 3.11

2.52 3.58 2.44 3.37

3.03 3.54 3.71 3.33 3.60

2.04 2.08 1.95

1.97 1.96 2.13 2.04

10.30 10.58 10.05 10.44 9.94

2.90 3.77 3.90 3.71 3.87

3.28 3.48 3.36 3.18

3.30 3.09 3.17

nMag pulsec (PV)

2512 2476 2501 2498 2502

2477 2476 2439 2477

2529 632 633

C0SAe (mg/L)

nMag Dzf (nm) η0g

katt,1h (1/day) α1i

Smaxj (mg/g)

Porous Medium: Unwashed Ottawa Sand (40−50 mesh) none 202.6 ± 5.1 1.16 × 10−1 26.64 4.26 × 10−2 0.066 −1 none 177.0 ± 2.2 1.16 × 10 54.96 8.54 × 10−2 0.072 GA-1000 + HEC10−100 181.3 ± 1.0 1.19 × 10−1 53.76 8.83 × 10−2 0.030 Porous Medium: Unwashed Crushed Berea Sandstone (60−170 mesh), Low Pore-Water Velocity none 195.0 ± 1.0 2.78 × 10−1 172.46 2.88 × 10−2 0.859 HEC10−1000 249.0 ± 4.0 2.65 × 10−1 174.39 3.17 × 10−2 0.444 GA-1000 + HEC10−100 192.8 ± 2.2 2.55 × 10−1 106.08 1.83 × 10−2 0.542 HEC10−1000 (PF) 157.7 ± 2.6 2.64 × 10−1 1.49 2.61 × 10−4 0.120 Porous Medium: Unwashed Crushed Berea Sandstone (60−170 mesh), High Pore-Water Velocity none 186.6 ± 0.6 8.41 × 10−2 797.76 8.56 × 10−2 0.897 HEC10−1000 259.2 ± 5.9 7.95 × 10−2 541.2 6.07 × 10−2 0.464 GA-1000 185.5 ± 2.7 8.68 × 10−2 450.24 4.74 × 10−2 0.477 GA-1000 + HEC10−100 192.4 ± 1.3 8.34 × 10−2 424.08 4.51 × 10−2 0.488 CALFAX-1000 242.7 ± 5.1 8.44 × 10−2 440.4 4.90 × 10−2 0.484

C0nMagd (mg/L)

13.06 2.41 10.45 9.02 13.6

3.54 0.002 2.25 0

0 0 0

katt,2k (1/day)

55.1 77.8 71.7 72.0 68.7

10−3 10−4 10−3 10−4 10−3 × × × × ×

38.8 77.8 66.8 92.8

5.9 × 10−4 3.6 × 10−7 3.9 × 10−4 0 1.4 2.7 1.1 9.6 1.5

96.6 80.1 93.3

nMag in effluentm (%)

0 0 0

α2l

a 2 = 2 ± 0.04 m/day; 10 = 10 ± 0.40 m/day pore-water velocity. bWidth of injected tracer pulse. cWidth of injected nMag pulse. dInjected nMag concentration. eChemical additive name and injected concentration; PF = preflood, otherwise coinjected. fCumulants mean nMag diameter in injected suspension and standard deviation for n = 3 measurements. gSingle collector efficiency, calculated using correlation by Tufenkji and Elimelech.62 Hamaker constants were taken from Toikka et al.63 hModel fitted first-order attachment rate to site 1. iCalculated collision efficiency for site 1, using the correlation from eq 4. jModel fitted maximum solid phase retention of nMag to site 1. kModel fitted first-order attachment rate to site 2. lCalculated collision efficiency for site 1, using the correlation from eq 4. mPercentage of injected nMag recovered in column effluent.

tracer pulseb (PV)

vpa (m/day)

Table 2. Summary of Experimental Conditions and Results for nMag Transport Studies Conducted in 40−50 Mesh Ottawa Sand and 60−170 Mesh Crushed Berea Sandstone in API Brine

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capacity of crushed Berea sandstone, which could be due to improved stabilization of the nMag suspension or blocking of nMag attachment sites through sacrificial polymer adsorption. Effect of Flow Rate on nMag Mobility. To explore the effects of flow rate on nMag mobility, five column studies were conducted in crushed Berea sandstone at a higher pore-water velocity of vp = 10 m/day (Figure 3). In the absence of any

with 625 mg/L nMag increased nMag mass recovery in the column effluent from 80% to 93% (see Figure 2A and Table 2). The nanoparticle transport model accurately captured the observed improvement in nMag mobility; here, the fitted maximum retention capacity was reduced 2.5-fold (from 0.072 mg/g to 0.030 mg/g). Although the polymer addition improved nMag mobility, the relatively high baseline mobility of nMag observed in 40−50 mesh Ottawa sand limits the potential benefit of additives in this system. Hence, subsequent nMag mobility studies were performed in columns packed with crushed Berea sandstone saturated with API brine. nMag Mobility in Crushed Berea Sandstone. A set of three column experiments was performed to investigate the effects of polymer additives on nMag transport in crushed Berea sandstone at a pore-water velocity of vp = 2.0 m/day. In the absence of any chemical additive, only 39% of the applied nMag was recovered in column effluent, following a 3 PV injection of nMag (2500 mg/L) in API brine (see Figure 2B, as well as Table 2). Co-injection of nMag with either 1000 mg/L Gum Arabic + 100 mg/L HEC-10 or 1000 mg/L HEC-10 increased the effluent recovery of nMag more than 1.7-fold, from 39% to 67% and 78%, respectively. For all crushed Berea sandstone experiments, the two-site mathematical model was implemented to simulate nanoparticle attachment to sites that have a limiting retention capacity (site 1) and sites that have an unlimited capacity in the time scales considered in this study (site 2). This two-site modeling approach was invoked to account for the physically and chemically heterogeneous surfaces in the crushed Berea sandstone.44,45 Generally, the fitted two-site model was able to capture the delayed asymmetrical nMag breakthrough curve and the effluent concentration plateau (Figure 2B). However, the increasing height of the concentration plateau observed at 3−4 PVs in two of the experiments deviated slightly from the model fits. Since the plateau height is primarily a function of katt,2, this discrepancy suggests that, contrary to the model assumption, site 2 may exhibit a limiting capacity that causes the effective attachment rate to decrease as nMag is deposited. Unfortunately, without additional parameter constraints, the limiting retention capacity of site 2 could not be uniquely estimated, because of difficulties in fitting four parameters to a single breakthrough curve. In the absence of chemical additives, the nanoparticle transport model yielded a maximum retention capacity for site 1 (i.e., Smax,1) of 0.859 mg/g, which is more than 13 times larger than the value obtained for 40−50 mesh Ottawa sand (0.072 mg/g) under identical conditions (see Table 2). The observed increase in nMag retention capacity (Smax,1) and the corresponding reduction in mobility were attributed to the much larger SSA of crushed Berea sandstone (22.54 m2/g), which contains fines and physical and chemical surface heterogeneity,52,53 in comparison to 40−50 mesh Ottawa sand (SSA = 0.013 m2/g). The fitted attachment rate for site 2 was ∼50 times smaller than that of site 1 (3.54 vs 172.46 1/day, respectively). As a consequence of the low attachment rate for site 2, a mass balance calculation indicated that only 26% of the total nMag retention observed in crushed Berea sandstone was attributable to site 2 surfaces. Co-injection of nMag with either Gum Arabic + HEC-10 or HEC-10 yielded site 1 retention capacities of ∼0.54 mg/g and ∼0.44 mg/g (see Table 2), which were, respectively, 1.6 and 1.9 times lower than the value obtained when nMag was introduced without a stabilizing agent (Smax,1 = 0.86 mg/g). These findings indicate that the co-injection of polymers greatly reduced the retention

Figure 3. Measured and simulated effluent breakthrough curves obtained for pulse injections of nMag (2500 mg/L in API brine) alone or co-injected with polymer or surfactant in crushed Berea sandstone at a nominal pore-water velocity of vp = 10 m/day. The dashed line corresponds to a representative nonreactive tracer test; experimental conditions for each breakthrough curve and fitted model parameters are given in Table 2.

chemical additives, 55% of the nMag passed through the column, compared to 39% effluent mass recovery at a porewater velocity of vp = 2 m/day. This observation is consistent with other nanoparticle transport studies where increased flow velocity resulted in reduced nanoparticle retention by the solid phase and increased mobility.54,55 Co-injection of 1000 mg/L HEC-10 increased effluent recovery of nMag by 41% (from 55% to 78%), while the co-injection of 1000 mg/L Gum Arabic or 1000 mg/L Gum Arabic + 100 mg/L HEC-10 increased nMag recovery by ∼30% (from 55% to 72%). The co-injection of Calfax achieved a slightly lower improvement in nMag mobility, increasing effluent recovery by 25% (from 55% to 69% mass breakthrough). When compared to results for the slower flow velocity, nMag recovery and fitted Smax,1 values were almost identical for experiments performed with the coinjection of 1000 HEC-10 (78% vs 78%, and 0.44 mg/g vs 0.46 mg/g) or 1000 mg/L Gum Arabic + 100 mg/L HEC-10 (72% vs 67%, and 0.54 mg/g vs 0.49 mg/g). These findings indicate that the observed improvements in nMag mobility were not sensitive to flow velocity, and they suggest that the Gum Arabic and HEC-10 readily adsorb onto crushed Berea sandstone. In both fast and slow-flow experiments, the co-injection of 1000 mg/L HEC-10 with nMag resulted in a large reduction in site 1 and site 2 attachment rate parameters (see Table 2). However, both of these breakthrough curves exhibited tailing (Figures 2B and 3) that contrasted with the steep decline in effluent concentrations observed when nMag was co-injected with either Gum Arabic or Calfax. This tailing behavior may be due to the injection of lower viscosity, polymer-free, API brine (1.4 × 10−3 Pa s) immediately after the higher viscosity nMag + HEC-10 (1000 mg/L, 2.9 × 10−3 Pa s) pulse (Figure 1). The sequential injection of a higher viscosity solution, followed by a lower viscosity solution, may lead to an unstable fluid/fluid G

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Energy & Fuels interface and viscous fingering, which would be manifested as concentration tailing in the nMag effluent breakthrough curve. A similar phenomenon has been observed previously in miscible displacement studies with fluids of different viscosities in porous media.56,57 The fitted attachment rate parameters (katt) indicate that surfactant co-injection reduced nMag deposition rate kinetics, especially for site 2 (Table 2). For all crushed Berea sandstone column experiments, site 1 attachment rates (katt,1) were reduced by an almost constant amount (41.8% ± 6.6%), regardless of surfactant or polymer type. However, site 2 attachment rates (katt,2) were affected much more strongly by the type of co-injected stabilizing agent (up to 99.4% reduction for HEC-10 at 2 m/d). These results suggest that the coinjected stabilizing agent affected the nMag retention to site 2 much more than retention to site 1, which is consistent with a greater affinity for site 2. In all cases, nMag retention on site 1 reached the maximum retention capacity (Smax,1) before the injected nMag pulse eluted from the column, as indicated by the concentration plateau observed in the effluent breakthrough curves. For this reason, deposition to site 1 was limited by the retention capacity rather than the attachment rate. Generally, attachment rates for both site 1 and site 2 were higher in crushed Berea sandstone at 10 m/d than at 2 m/d. Scaling of attachment rates with velocity is consistent with colloid filtration theory (CFT)58 and has been observed in other nanoparticle−porous media systems.34,59 Colloid filtration theory predicts that the nanoparticle attachment rate can be calculated by ⎡ 3(1 − θw )vp ⎤ ⎥αη0 katt = ⎢ ⎢⎣ ⎥⎦ 2dc

Figure 4. Measured effluent breakthrough curves obtained for a 3 PV injection of HEC-10 alone (1000 mg/L in API brine), followed by a 3 PV injection of API brine, a 3 PV injection of nMag alone (2500 mg/L in API brine), and 3 PV of API brine in crushed Berea sandstone at a pore-water velocity of vp = 2 m/day. Symbols represent experimental data corresponding to the species listed in the legend, while the solid line represents the model fit to nMag pulse injection.

(ca. 8000 mg/L) at 25 °C.25 When nMag (2500 mg/L) was then injected into the HEC-10-treated column, 93% of the applied nMag passed through the column, yielding an nMag breakthrough curve that almost coincided with that of the nonreactive tracer. Thus, the HEC-10 preflood resulted in 20% greater nMag mobility, compared to the co-injection of nMag and HEC-10 under identical conditions. The fact that such favorable nMag mobility was achieved with a preflood indicates that HEC-10 adsorbed onto crushed Berea sandstone and served to screen or block potential nMag attachment sites. This finding is consistent with prior studies of quantum dot transport in the presence of residual coating polymer (PAAOA), which was shown to reduce quantum dot attachment near inlets of columns packed with Ottawa sand.26,28 The nanoparticle transport model was able to capture the nMag breakthrough curve obtained after the HEC-10 preflood, including the slightly delayed nMag breakthrough time and effluent concentration plateau (Figure 4). The resulting model parameters indicate that the HEC-10 preflood greatly reduced nMag attachment rates to both site 1 and site 2 (see Table 2). In the case of site 2, the fitted katt,2 value was negligible, suggesting that the adsorbed HEC-10 completely screened attachment sites associated with site 2. In addition, the nMag retention capacity for site 1 (Smax,1) was reduced 4-fold, compared to the 1000 mg/L HEC-10 co-injection experiment, and 8-fold in the absence of stabilizing agent. These results further support the conclusion that sacrificial adsorption of HEC-10 serves to block nMag attachment sites, which led to greatly improved nMag mobility. nMag Deposition. SEM images were obtained for samples collected from “clean” and nMag-treated columns in order to provide visual evidence of nMag deposition on Ottawa sand and crushed Berea sandstone. An initial set of SEM images was obtained for Ottawa sand saturated with API brine before and after the injection of a 3 PV pulse of nMag (2500 mg/L) without a stabilizing agent (see Figure 5). The sequence of SEM images on the left shows increasing magnification of a clean quartz grain, which has limited features on the surface, even at the highest magnification. In contrast, the SEM images on the right show a similar grain exposed to a 3 PV pulse of nMag (2500 mg/L in API), and illustrate deposition of nMag on the surface. Similarly, Figure 6 shows SEM images of 60−

(4)

where dc is the diameter of a porous media collector, α the collision efficiency (or the number of particle collisions with the solid surface that result in attachment), and η0 the single collector efficiency (or the frequency of particles in the bulk fluid flow that interact with the solid surface). The influence of stabilizing agents on the attachment rate can be attributed to modification of the collision efficiency (α) parameter by improved particle stabilization, which is an effect that has been observed with natural organic matter and zerovalent iron nanoparticles.60,61 Polymer Preflood in Crushed Berea Sandstone. To further elucidate the mechanism responsible for the observed enhancements in nMag mobility (e.g., blocking nanoparticle attachment sites, improved suspension stability), a “pre-flood” experiment was performed with HEC-10 in crushed Berea sandstone at a pore-water velocity of vp = 2 m/day. The injection sequence consisted of 3 PVs of 1000 mg/L HEC-10 in API brine, followed by 3 PVs of API brine, 3 PVs of 2500 mg/L nMag in API brine, and finally 3 PVs of API brine. Effluent concentration measurements indicated that HEC-10 breakthrough occurred at ∼1.5 PVs, approached a relative concentration of ∼0.9 at 4 PVs, and then rapidly declined when API brine was reintroduced into the column (see Figure 4). Approximately 28% of the applied HEC-10 mass was retained by the crushed Berea sandstone (d50 = 154 μm), which corresponds to a column-averaged adsorption capacity of 0.56 mg HEC-10/g solid. This value is consistent with batch measurements of anionic surfactant adsorption on crushed Berea sandstone, which reached a maximum capacity of 0.96 mg/g at an equilibrium surfactant concentration of 0.8 wt % H

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Figure 5. Scanning electron microscopy (SEM) images of (A) blank 40−50 mesh unwashed Ottawa sand and (B) nMag retained on 40−50 mesh unwashed Ottawa sand. Insets show increased magnification views. In each photomicrograph, the scale bar is shown in the lower left corner.

recovered in column effluent at a pore-water velocity of 2 m/ day. Under identical conditions, however, only 39% nMag recovery was observed in 60−170 mesh crushed Berea sandstone, indicating that the presence of fine materials can severely limit mobility. In an effort to improve nMag mobility at minimal cost, three commercially available polymers and surfactants (HEC-10, Gum Arabic, and Calfax 16L-35) were selected for column testing, based on their stability in API brine. Co-injection of either 1000 mg/L HEC-10, Gum Arabic, or Calfax demonstrated improved mobility, with effluent recoveries ranging from 68% to 78% of the injected nMag mass. A preflood column experiment, consisting of a 3 PV pulse of 1000 mg/L HEC-10, followed by 3 PV of 2500 mg/L, yielded even greater mobility (92% effluent recovery), and indicated that the adsorption of HEC-10 on the solid phase served to block nanoparticle attachment sites. Mathematical modeling results provided further support for this mechanism, demonstrating that the maximum retention of nMag (Smax,1

170 mesh sized crushed Berea sandstone saturated with API brine before and after injection of 2500 mg/L nMag with and without a 1000 mg/L HEC-10 preflood. The increased deposition of nMag apparent in the SEM images is consistent with the much lower nMag effluent recoveries and higher Smax,1 values obtained for crushed Berea sandstone, compared to Ottawa sand (Table 2). In addition, the SEM images indicate that nMag did not achieve complete or monolayer coverage under these experimental conditions, which is consistent with a limited retention capacity that has been observed for other nanoparticle−porous media systems.26,38,42

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CONCLUSIONS The synthesis of nMag suspensions that are stable in highsalinity environments and exhibit high mobility in porous media are essential for successful deployment as contrast agents under reservoir conditions. In unwashed 40−50 mesh Ottawa sand, 97% of the injected nMag (2500 mg/L in API brine) was I

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Figure 6. SEM images of (a) blank 60−170 mesh crushed Berea sandstone, (b) nMag retained on crushed Berea sandstone with HEC-10 preflood, and (c) nMag retained on crushed Berea sandstone without HEC-10 preflood. Insets show increased magnification views. In each photomicrograph, the scale bar is shown in the lower left corner.

member companies of the Advanced Energy Consortium include Shell, Schlumberger, BP, Petrobras, Statoil, Total, BG Group, and Repsol. The viscometer used for this work was funded by National Institute of Health (NIH, Grant No. P41 EB002520). SEM imaging was performed at the Harvard University Center for Nanoscale Systems (CNS), a member of the National Nanotechnology Infrastructure Network (NNIN), which is sponsored by the National Science Foundation (under Award No. ECS-0335765).

values) decreased nearly 2-fold with co-injection and more than 4.5-fold following the preflood. These observed improvements in nMag mobility at high salinity and in porous media containing fine materials are promising, and they demonstrate the potential application of polymers as “sacrificial agents” that block attachment sites and improve nanoparticle delivery in reservoir formations. Future studies will focus on the evaluation of nMag and polymer or surfactant injections in consolidated core-flood tests at temperatures and pressures that are representative of reservoir conditions.

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ASSOCIATED CONTENT

(1) Kuchuk, F.; Saleri, N., Middle East Well Evaluation Review: Predicting the Unpredictable. In Middle East & Asia Reservoir Review, Vol. 18; Schlumberger: Sugar Land, TX, 1997. (2) Muggeridge, A.; Cockin, A.; Webb, K.; Frampton, H.; Collins, I.; Moulds, T.; Salino, P. Recovery Rates, Enhanced Oil Recovery and Technological Limits. Philos. Trans. R. Soc., A 2014, 372 (2006), 20120320. (3) Chopra, S.; McConnell, I. M., Using Interwell Chemical Tracers and the Coherence Cube to Understand Reservoir Communication. Oil Gas J. 2004, 102, (19). (4) Coronado, M.; Ramírez-Sabag, J.; Valdiviezo-Mijangos, O. Double-Porosity Model for Tracer Transport in Reservoirs Having Open Conductive Geological Faults: Determination of the Fault Orientation. J. Pet. Sci. Eng. 2011, 78, 65−77. (5) Coronado, M.; Ramírez-Sabag, J.; Valdiviezo-Mijangos, O.; Somaruga, C. A Test of the Effect of Boundary Conditions on the Use of Tracers in Reservoir Characterization. Geofis.́ Int. 2009, 48 (2), 185−194. (6) Prodanović, M.; Ryoo, S.; Rahmani, A. R.; Kuranov, R.; Kostmar, C.; Milner, T. E.; Johnston, K. P.; Bryant, S. L.; Huh, C. Effects of Magnetic Field on the Motion of Multiphase Fluids Containing Paramagnetic Particles in Porous Media. In SPE/DOE Symposium on Improved Oil Recovery; Society of Petroleum Engineers (SPE): Tulsa, OK, USA, 2010; Vol. 2, pp 893−911. (7) Ryoo, S.; Rahmani, A. R.; Yoon, K. Y.; Prodanović, M.; Kotsmar, C.; Milner, T. E.; Johnston, K. P.; Bryant, S. L.; Huh, C. Theoretical and experimental investigation of the motion of multiphase fluids containing paramagnetic nanoparticles in porous media. J. Pet. Sci. Eng. 2012, 81, 129−144. (8) Bagaria, H. G.; Xue, Z.; Neilson, B. M.; Worthen, A. J.; Yoon, K. Y.; Nayak, S.; Cheng, V.; Lee, J. H.; Bielawski, C. W.; Johnston, K. P. Iron Oxide Nanoparticles Grafted with Sulfonated Copolymers are Stable in Concentrated Brine at Elevated Temperatures and Weakly Adsorb on Silica. ACS Appl. Mater. Interfaces 2013, 5, 3329−3339.

S Supporting Information *

The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.energyfuels.5b01785. Transmission electron microscopy (TEM) image of a TEOS AMPs-co-AA coated iron oxide nanoparticle cluster (Figure S1), TEM image with energy dispersive X-ray spectroscopy (EDS) mapping of nMag aggregate (Figure S2), EDS spectrum of nMag attached to Ottawa sand (Figure S3), and model sensitivity to katt and Smax for the 2500 mg/L nMag injection experiment in 40−50 mesh Ottawa sand (Figure S4) (PDF)

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REFERENCES

AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. Present Addresses §

Aramco Services Company: Aramco Research Center− Boston, 400 Technology Square, Cambridge, MA 02139, USA. ∇ John and Willie Leone Family Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, University Park, PA 16802, USA. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The authors thank Jae Jin (Lisa) Han for her assistance with the permeability measurements. This work was supported by the Advanced Energy Consortium (Project No. BEG-08-11); J

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DOI: 10.1021/acs.energyfuels.5b01785 Energy Fuels XXXX, XXX, XXX−XXX

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DOI: 10.1021/acs.energyfuels.5b01785 Energy Fuels XXXX, XXX, XXX−XXX