Fuel 148 (2015) 127–138

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Fuel

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Dynamic interfacial tension and wettability of shale in the presenceof surfactants at reservoir conditions

http://dx.doi.org/10.1016/j.fuel.2015.01.0770016-2361/� 2015 Elsevier Ltd. All rights reserved.

⇑ Corresponding author. Tel.: +1 307 766 6866.E-mail address: ssaraji@uwyo.edu (S. Saraji).

Vahideh Mirchi, Soheil Saraji ⇑, Lamia Goual, Mohammad PiriDepartment of Chemical and Petroleum Engineering, University of Wyoming, 1000 E. University Avenue, Laramie, WY 82071-2000, USA

h i g h l i g h t s

� IFT/CA measurements were performed on shale systems at reservoir conditions.� A framework is established to study surfactant concentration/brine chemistry on shales.� Increase in salinity and anionic surfactant concentration resulted in higher CA.� Shale remained water–wet due to low adsorption of nonionic surfactant.� Use of tap water versus reservoir brine resulted in lower IFT and work of adhesion.

a r t i c l e i n f o

Article history:Received 13 September 2014Received in revised form 22 January 2015Accepted 23 January 2015Available online 7 February 2015

Keywords:Shale oilSurfactantInterfacial tensionContact angleWettability

a b s t r a c t

The production of oil from shale formations often requires the utilization of chemical surfactants as addi-tives in fracturing fluids in order to change the characteristics of oil/brine interfaces and/or induce wet-tability alteration at the shale surface. Although the effect of some surfactants on the interfacialproperties of shale oil systems has been investigated in the past, the limited data available in the litera-ture were mainly obtained at ambient conditions and thus may not be representative of fluid-rock inter-actions at actual reservoir conditions.

In this study, a new framework is proposed to investigate the effect of surfactants on fundamentalparameters governing fluid displacement in two brine/oil/shale systems (A and B) at reservoir conditions.The critical micelle concentration (CMC) of anionic and nonionic surfactants in brine and their adsorptionpropensity on shale was first determined by ultraviolet–visible spectroscopy and pendant drop method.Rising/captive bubble technique was validated for ultra-low interfacial tension systems then utilized tomeasure dynamic interfacial tensions and contact angles in the presence of surfactants in Systems Aand B at ambient and reservoir conditions. The effects of pressure and temperature, surfactant concentra-tion, and brine chemistry on the above-mentioned parameters were investigated in a systematic manner.The results revealed that nonionic surfactants adsorb much less on shales than anionic surfactants. As aresult, shale samples used in this study remained strongly water–wet with the nonionic surfactantregardless of surfactant concentration and brine chemistry. The lowest work of adhesion was obtainedright above the CMC, which represents the optimum surfactant concentration. Moreover the use of tapwater instead of reservoir brine in System B was preferred due to a further reduction in IFT.

� 2015 Elsevier Ltd. All rights reserved.

1. Introduction

Unconventional shale oil and gas reservoirs are becomingincreasingly important to hydrocarbon supplies across the world.Shale rocks have intricate nano- and micro-scale pore networksand complex matrix mineralogy. They mainly consist of clay min-erals, carbonate/quartz grains, and organic matter. Their porosities

are typically less than 15% and their permeabilities are in the rangeof nano- to micro-Darcy [1]. Shale rocks are artificially fractured toimprove the poor permeability and pore connectivity in theses res-ervoirs; however, the presence of nano pores, micro pores, andmicro fractures in the matrix causes high capillary pressures inthe medium. Therefore only a limited portion of the original oilin place is recoverable by primary production. The rationale behindthis work is to reduce the capillary pressure of the system usingsurfactants as additives in fracturing fluids. Hence, more oil canbe produced due to further imbibition of brine into theses rocks.

128 V. Mirchi et al. / Fuel 148 (2015) 127–138

Capillary pressure is responsible for holding oil and brinephases during hydraulic fracturing processes and can be, for a cir-cular pore, calculated from Eq. (1), also known as Young–Laplaceequation, where cow is the oil–brine interfacial tension (IFT), how

is the contact angle (CA) at the three-phase contact line, and r isthe pore radius.

Pcow ¼2cowcoshow

rð1Þ

Reducing the capillary pressure by, for instance, using surfac-tants with hydraulic fracturing fluid, can potentially increase theamount of oil recovery from shale reservoirs. Surfactant moleculestend to accumulate at fluid–fluid and rock–fluid interfaces andhence reduce Pc by lowering cow and altering how on shale surfaces.

There are several suitable IFT measurement methods for sys-tems containing surfactants, among which the spinning drop tech-nique can be used to measure extremely low values (0.0001 mN/m) [2]. Yet, this method cannot be used at high pressure and itsmaximum temperature tolerance is 100 �C. On the contrary, thependant drop technique is the most suitable IFT measurement toolfor high-pressure/high-temperature conditions [3–6]; although itmay not be the best for ultra-low IFT systems. Likewise, severalmethods are available to characterize the relative wetting prefer-ence of a reservoir rock using core flooding or centrifugation suchas Amott and USBM (U.S. Bureau of Mines) Tests [7,8]. However,these methods are extremely time consuming especially for shalesamples and are not sensitive enough at neutral wettability [7].Pendant/sessile drop technique, on the other hand, can be utilizedto measure dynamic IFT and CA at reservoir conditions with agreater accuracy [9]. The results can be used in capillary pressurecalculations and pore-scale modeling.

Despite numerous studies on the impact of surfactants on thesurface properties of conventional rocks (i.e., carbonates and sand-stones) [10,11], limited studies are available on shale oil rocksespecially at reservoir conditions. The majority of existing litera-ture on shale rocks involves spontaneous imbibition tests in thepresence of surfactants as a function of several parameters suchas pH, salinity, and divalent cations [12–17]. Borysenko andcoworkers [18] performed spontaneous and forced imbibitionexperiments on crushed shale packs, sessile drop tests, and dielec-tric and NMR spectroscopy to characterize the wetting tendency onthree different shale rocks at ambient conditions. They found thatdifferent shales have different wetting states depending on theirpetrophysical properties. For instance, illitic and smectitic shalesare more hydrophilic and have higher surface activity whereaskaolinitic shales are preferentially oil–wet. Wang and co-workers[14] examined the wettability alteration of Bakken shale in thepresence of several surfactants using a modified Amott-Harveymethod. Surfactants could alter the wettability of shale cores fromoriginally oil–wet or intermediate-wet to water–wet. In anotherstudy, the same group suggested that surfactant concentration,brine salinity, and divalent ion concentration are the major factorsaffecting oil recovery from shales [12]. Takahashi and Kovscek [19]examined the wettability of low-permeability siliceous shale atdifferent pH values by using zeta potential measurements. Theyfound that shale was more water–wet at very high or very lowpH and interpreted the results based on surface force calculations.The adsorption tendency of surfactants on shale rocks canadversely affect their efficiency due to chemical losses. This phe-nomenon may be more significant on shale surfaces consideringthe higher surface area available for adsorption in these rocks.Zelenev and Champagne [20] measured the adsorption of micro-emulsions on shale fines through surface tension measurementsbefore and after equilibrium. Muherei and coworkers [21] alsoexamined the adsorption of two surfactants and their mixtureson sandstones and shales using the same method. They concluded

that nonionic surfactants tend to adsorb more on shales than onsandstones, possibly due to hydrophobic bonding.

The limited data on shale wettability currently available in theliterature were mainly obtained at ambient conditions and thusmay not be representative of fluid–fluid and fluid–rock interac-tions at actual reservoir conditions. The objective of this study isto establish a new framework to investigate the effect of anionicand nonionic surfactants on dynamic interfacial tensions and con-tact angles of surfactant-in-brine/oil/shale systems at reservoirconditions (3000–7000 psi, 80–116 �C). In other words, the inten-tion was not to focus on identifying the best surfactants fromrecovery standpoint for shale systems. Instead, we present, forthe first time, a detailed methodology for measuring the interfacialproperties of these systems, including shale substrate preparation,thin needle utilization, fluid pre-equilibration, in-line density mea-surements, all of which are critically important due to surfactantpartitioning in brine and oil phases. The experimental frameworkwas first validated with simple ultra-low IFT systems using the ris-ing/captive bubble technique, then successfully applied to twoshale systems (A and B) at ambient and reservoir conditions. Theeffect of pressure, temperature, surfactant concentration, and brinechemistry on IFT and CA were investigated in a systematic manner.For both shale systems, the work of adhesion was determined atvarious experimental conditions and its significance on improvedoil recovery was discussed.

2. Materials and methods

2.1. Shales

Two subsurface shale samples from different depths were uti-lized as substrates: Shale A (non preserved) and Shale B (pre-served). Micrographs of the two shale samples were acquiredusing high-resolution scanning electron microscopy (SEM) inback-scattered electron (BSE) mode, as shown in Fig. 1a and b.The elemental maps of these rocks were also obtained by energydispersive spectroscopy (EDS) and are presented in Fig. 1c and d.The pore size distribution of these shales is between 10 and400 nm [22]. The porosity and organic content are also providedin Table 1. Although both shales have similar porosities, their min-eralogy is very different. Shale A is a clay-rich rock with poresmainly associated with the organic matter. In contrast, Shale B isa dolomitic siltstone containing insignificant amounts of organicmatter. The zeta potentials of Shale A and B in distilled water weremeasured with a Zeta Potential Analyzer (Brookhaven InstrumentsCorporation) and the values are �25.2 and �26.4 mV, respectively.

2.2. Crude oils

Gibbs crude oil from Wyoming (Crude oil A) and reservoir oilfrom Shale B reservoir (Crude oil B) were employed in this study.The properties of these crude oils are presented in Table 2. Bothcrude oils were first centrifuged at 6000 rpm for one hour and thenfiltered with 0.8 and 0.5 lm filters before use. For IFT and CA val-idations, n-tetradecane (98%, Fisher Scientific) was used as a sub-stitute for oil.

2.3. Brines

Synthetic brine, tap water, and reservoir brine (from Shale Breservoir) were used as aqueous phases. The synthetic brine solu-tions were prepared with distilled-deionized water (resistivity of2.75 � 104 X m) and various NaCl (ACS grade, Fisher Scientific)concentrations. The dominant cations and anions in the reservoirbrine were Na+, Ca2+, Mg2+ and Cl�, as presented in Table 3. The

Fig. 1. SEM micrographs in BSE mode: (a) Shale A (1 kV voltage, 400 pA current, and 8 nm image resolution), (b) Shale B (1 kV voltage, 100 pA current, and 25 nm imageresolution). Elemental maps of rock samples using EDS: (c) Shale A (10 kV voltage, 3200 nA current, and �50 nm image resolution), (d) Shale B (10 kV voltage, 3200 nAcurrent, and �50 nm image resolution).

Table 1Physical characteristics of the shale samples.

Porosity, % Organic content, vol% Mineralogy (in order of abundance)

Shale A 1.3 8.3 Illite/smectite clays, feldspar, calcite, quartz, pyrite framboids, and organic matterShale B 1.5 <1 Dolomite, calcite, quartz, and illite clays

Table 2Properties of the crude oils. TAN: Total Acid Number, TBN: Total Base Number.

Density, g/cc 20 �C Viscosity, cp Asphaltene content, wt% TAN, mg of KOH/g TBN, mg of KOH/g Refractive index

Crude oil A 0.9 11.833 10.23 0.146a 2.466a 1.483Crude oil B 0.81 2.804 0.45 0.23 0.68 1.46

a Reported from Ref. [50].

Table 3Concentrations of dominant ions in tap water and reservoir brine.

Ions Tap water, ppm Reservoir brine, ppm

Na+ 8 78,950Ca2+ 47 15,320Mg2+ 14 1160Cl� 7 141,510SO4� 18 400

NO3� 10 –

V. Mirchi et al. / Fuel 148 (2015) 127–138 129

pH and resistivity of brine solutions were measured with a pHmeter (Phtestr 30, EUTECH). The reservoir brine had total dissolvedsolids (TDS) of 237,755 ppm, a pH of 4.27, and a resistivity of0.05 X m at 25 �C. This brine was filtered using a 0.1 lm syringefilter before any measurement. Tap water was used as a modelfracturing fluid for Shale B reservoir with a neutral pH and a TDSof 120 ppm, as shown in Table 3.

2.4. Surfactants

Surfactants include a liquid anionic surfactant (ammonium alkylether sulfate) from Stepan Chemical Company and a nonionic sur-factant from ChemEOR Company. Phase behavior tests were per-formed with these surfactants at a brine/oil ratio of one and inthe presence of crushed shale particles. Both surfactants were solu-ble in brine with insignificant turbidity and no visible microemul-sion phase between oil and brine within the concentration rangeused in this study. Sodium dodecane sulfate (SDAS) (99%, Fluka),diethylene glycol monohexyl ether (C6E2) (98%, Aldrich), and dioc-tyl sodium sulfosuccinates (AOT) (98%, Aldrich) were also used forIFT and CA validations. The adsorption of surfactants on shaleswas measured using a double-beam ultraviolet–visible (UV–Vis)spectrophotometer (Cary 4000, Varian, Inc.). The mixing of surfac-tant solutions and shale fines was performed with an incubatingmini shaker (VWR International LLC). Based on the HRTEM (HighResolution Transmission Electron Microscopy) images shown in

Fig. 2. TEM micrographs in BF mode (200 kV voltage, and pixel resolution of 0.24 nm) for micelles of (a) Surfactant A, and (b) Surfactant B.

130 V. Mirchi et al. / Fuel 148 (2015) 127–138

Fig. 2, the average size of surfactant micelles was about 100 nm.This is within the pore size distribution of shales (see Section 2.1),therefore surfactant micelles can imbibe into micro pores, microfractures, and the majority of nano pores.

2.5. Experimental setup and procedure

Dynamic interfacial tensions and contact angles of surfactant-in-brine/oil/shale systems were measured by rising/captive bubbletensiometry enhanced by video-image digitization technique. Thissystem is capable of measuring dynamic IFT as well as advancingand receding CA at reservoir conditions (up to 15,000 psi and200 �C). The experimental set up shown in Fig. 3 includes a Hastel-loy measurement cell, a high-resolution camera, a Yamato oven, aHastelloy equilibrium cell, a dual-cylinder 5000-series HastelloyQuizix pump to supply stable flow rates and pressures during themeasurements, and an in-line density meter (Anton Paar DMAHPM). The IFT analysis is very sensitive to input parameters suchas the density difference between fluid phases. This differencemust be measured very accurately to reduce the error in IFT anal-ysis especially for ultra-low values; however, it has been very com-mon in the literature to calculate density values numerically[23,24]. In this work, we measured the density of fluids using an

Fig. 3. Schematic of the experimental setup: (a) nitrogen cylinder, (b) mechanical convecmeasurement cell, (g) heating jackets, (h) RTD, (i) light source, (j) apochromatically coRosemount pressure sensor, (n) current source, (o) temperature control system, (p) dasubstrate, (u) movable tray, (v) crystal holder, (w) fluid level observation opening, (x) h

in-line density meter at actual experimental conditions in orderto obtain more accurate IFT data.

For CA measurements, the shale samples were cut with a preci-sion saw and then polished using a polishing apparatus at 100 rpmfor 40 min. Silicon carbide powder (18 lm) and diamond suspen-sion (3 lm) were used during the polishing process in order to gen-erate a smooth shale surface and to remove irregular and unevenareas created during the cutting process. The shale substrate wasfirst mounted on the rock sample holder (Fig. 3v) inside the mea-surement cell and the cell was subsequently filled with the desiredbrine solution. After adjusting pressure and temperature to theexperimental conditions, the system was left for at least six (6)hours so that the shale surface and brine solution reached equilib-rium. Pre-equilibrium of fluids prior to measurement is a criticalfactor affecting IFT and CA measurements, particularly in systemscontaining surfactants. Crude oil, pre-equilibrated with brine forseveral hours (overnight) inside the equilibration cell (Fig. 3d) atthe experimental conditions, was then injected into the measure-ment cell though a needle (0.3–2.1 mm outside diameter)approaching the surface from below (captive bubble method) witha very small flow rate (0.001 ml/min) and an overall time of six (6)hours for each measurement. Images of oil bubbles were capturedat 5 s intervals while the bubble was slowly growing or shrinking

tion oven, (c) dual-cylinder Quizix pump, (d) equilibration cell, (e) density meter, (f)rrected lenses and CCD camera, (k) adjustable stand, (l) anti-vibration table, (m)

ta acquisition computer, (q) shelf cart, (r) IFT/CA needle, (s) fluid bubble, (t) solidorizontal drive shaft, and (y) vertical drive shaft.

Table 4IFT results for water/n-tetradecane/C6E2 system.

Lin et al. [25] This study (Pendant drop)

(Spinning drop) (Pendant drop)

cab , mN/m 0.288 0.286 ± 1% 0.289 ± 3.27%cba , mN/m 0.186 0.210 ± 5.7% 0.207 ± 4.37%cax , mN/m 0.360 0.371 ± 0.8% 0.350 ± 2.35%

Table 6Contact angle results for water/n-tetradecane/SDAS system.

Bargeman et al. [27] This study

h, deg. 161 167

V. Mirchi et al. / Fuel 148 (2015) 127–138 131

beneath the shale surface using a Quizix pump. The density mea-surement module was also used to measure the equilibrium densityof oil and brine phases at the experimental conditions. The capturedimages were analyzed to obtain IFT values using the AxisymetricDrop Shape Analysis (ADSA) software by fitting the drop profile tothe Young–Laplace equation [9]. Also, a MatLab code and the ImageJsoftware were employed to detect the tangent value on the imagesfor CA measurements.

3. Validation of interfacial tension and contact anglemeasurment method

3.1. Interfacial tension

In order to validate the pendant drop/rising bubble technique forlow interfacial tension systems, two IFT measurements were per-formed using ultra-thin needles (e.g., 0.3 mm outside diameter) toreach Bond numbers close to unity. In these tests, surfactants, brine,and oil were mixed in a container and left to equilibrate for severaldays. Each liquid phase was then retrieved from the container forIFT measurements. The results were compared with literature val-ues measured by both spinning drop and pendant drop techniques[25]. The first measurement was conducted on water/n-tetrade-cane/C6E2, as shown in Table 4. In this table, cab is the IFT of liquida (oil-rich phase) in liquid b (surfactant-rich phase) and cax is theIFT of liquid a (oil-rich phase) in liquid x (water-rich phase) at25 �C and atmospheric pressure. For the second measurement,water/AOT/NaCl/heptane were used with the same preparationand measurement procedure as mentioned earlier. The results aregiven in Table 5 where cax is the IFT of liquid a (oil-rich phase) inliquid x (water-rich phase). A comparison between our resultsand the literature data demonstrates that the pendant drop tech-nique is quite reliable for ultra-low IFT measurements.

3.2. Contact angle

Although this technique was previously validated for contactangle measurements using Decane/Air/Teflon system [26], we fur-ther tested its accuracy and reproducibility with ultra-low IFT sys-tems such as water/n-tetradecane/SDAS at ambient conditions.First, a drop of water containing SDAS was placed on top of a Tef-lon-coated solid surface, which was immersed in tetradecane (ses-sile drop method). Then CA measurement was performed using thesame procedure as in Ref. 26. Table 6 indicates that our results arein good agreement with the literature data [27].

4. Original shale wettability

Three relatively quick tests were performed to examine the ori-ginal wettability of Shale A and Shale B surfaces. The wettability of

Table 5IFT results for water/AOT/NaCl/heptane system.

Aveyard et al. [51] (Spinning drop)

cax , mN/m 0.085

the shale samples was first examined by placing one drop of bothcrude oil and distilled water on dry shale surfaces without anyprior chemical treatment (Fig. 4a and b). The oil drop immediatelyimbibed into both samples while the water drop remained on thesurface with a small constant angle. Note that this behavior maynot necessarily represent the wetting state of the shale rocks sincethe surface tension of oil–air is much smaller than that of water–air system. Thus, the threshold capillary pressures of these twofluid systems are not comparable. The SEM micrographs in Fig. 1indicate that there are pores in these shales associated with theorganic matter. These pores are presumably strongly oil–wet andcan spontaneously imbibe crude oil from the shale surface. How-ever, Dehghanpour and coworkers [16] classified their organicshale samples as water–wet, based on imbibition tests. The authorsstipulated that both water adsorption and capillary forces shouldbe involved in the determination of shale wettability. Accordingly,contact angle measurements in the presence of both oil and brinephases might offer a better characterization of shale wettability atgiven P and T conditions.

The second method used to estimate the degree of wetting ofshales was a flotation test recommended by API for strongly wettedsystems [7]. In this test, distilled water, crude oil, and crushed shalepowder (>150 lm) were placed in a glass bottle and hand-shaken.As depicted in Fig. 4c for Shale A, some shale grains clusteredtogether at the bottom of the bottle forming small oil globuleswhile some of them were suspended at the oil–water interface.While, grains of Shale B were settled at the bottom of the bottle(cf. Fig. 4d). These two configurations are representative of rockswith weakly and strongly water–wet behaviors, respectively.

In the third method, the dynamic contact angles of crude oils Aand B on polished samples of shales A and B were measured in thepresence of distilled water at ambient conditions and are illus-trated in Fig. 4e and f. The measured angles were 14.92 ± 1.03�and 14.45 ± 1.46� respectively, which imply strongly water–wetsurfaces. These macroscopic angles represent an average wettingbehavior of the entire rock surface since shale rocks consist of var-ious minerals and organic matter. Similar contact angle valueswere obtained when the shale substrates were immersed in crudeoil overnight prior to the measurements.

Lastly, the impact of initial exposure of shale samples tocrude oil/brine on dynamic contact angle was studied. A shalesubstrate was equilibrated with reservoir brine for about 12 h,

Lin et al. [21] (Pendant drop) This study (Pendant drop)

0.086 ± 1% 0.0869 ± 3.79%

(a) (b)

(c) (d)

(e) (f)

Oil

Distilled water

Crushed shale

Oil bubble

Distilled water

Shale surface

Fig. 4. Drops of crude oil (left) and distilled water (right) placed on: (a) Shale A, and (b) Shale B. Flotation tests for water–oil and shale mixtures at ambient conditions: (c)Shale A, (d) Shale B. Dynamic contact angle of crude oil/distilled water on polished shale surface: (e) Shale A, and (f) Shale B.

132 V. Mirchi et al. / Fuel 148 (2015) 127–138

while the second substrate was initially immersed in the crude oilovernight. Bulk crude oil was gently removed from the surface ofthe second substrate before immersion in reservoir brine solution.The measured dynamic contact angles of reservoir oil and reservoirbrine on shale surfaces (captive bubble configuration) were17.73 ± 2.98� and 24.67 ± 0.65�, on the first and second substrates,respectively. The slight difference between these two values (i.e.,7�) suggests insensitivity of wettability of the shale substrates toinitial exposure of substrates to test fluids.

The representative elementary area (REA) of shale rocks waspreviously characterized to be less than 300 ⁄ 300 lm2 [22]. REAis defined as the minimum average area above which the macro-scopic characteristics of the porous media remain constant. Here,the area of oil bubbles created on the shale surfaces in all sets ofmeasurements was more than the REA mentioned earlier as theminimum diameter of our needles was 0.3 mm. Therefore, onemay consider the measured contact angle values representativeof the system at the macro scale.

5. Results and discussion

Two different shale systems were investigated: System A (shaleA, crude oil A, anionic surfactant, and synthetic brine with variousNaCl concentrations) at ambient and high P–T (3000 psi and 80 �C)and System B (shale B, crude oil B, nonionic surfactant, reservoirbrine and tap water) at reservoir conditions (6840 psi and116 �C). Prior to IFT/CA measurements, the CMC and adsorptionpropensity of surfactants on shale was measured for Systems Aand B using various brines.

5.1. CMC measurements

UV–Vis spectroscopy and pendant drop tests were employed toestimate the CMC of surfactants in Systems A and B. In the UV–Vis

spectroscopy method, we measured the light absorbance of brinesolutions with various surfactant concentrations at wavelengthsof 500 nm (reservoir brine) and 637 nm (5 M synthetic brine).The CMC manifested as a sudden change in the slope of the lightabsorbance versus concentration line. Such a break occurredbetween 0.02 and 0.03 wt% for Surfactant A (cf. Fig. 5a) andbetween 0.005 and 0.01 wt% for Surfactant B (cf. Fig. 5c). In orderto verify these values, the interfacial/surface tensions of SystemsA and B were measured at different surfactant concentrationsusing the rising/captive bubble method. A sharp initial decreasein interfacial/surface tension with increasing surfactant concentra-tion was seen up to the CMC for both systems. According to a pre-vious study, surfactants lay flat at the interface when theirconcentration is much lower than the CMC [28]. However as theirconcentration increases, they start forming a monolayer at theinterface, which leads to an increase in the interfacial pressureand a reduction in both interfacial energy and interfacial tension.Fig. 5b and d reveal that the CMC was reached at 0.03 wt% for Sys-tem A and 0.01 wt% for System B, in good agreement with the UV–vis measurements. Fig. 5b also indicates a shift in CMC from 0.03 to0.05 wt% by diluting brine solution from 5 to 0.1 M, which is inaccord with previous studies [29,30]. This behavior is known assalting out process which reduces the required surfactant concen-tration to form micelles [31].

5.2. Surfactant adsorption

Using UV–Vis spectroscopy, the adsorption of anionic and non-ionic surfactants on shale fines were measured at ambient condi-tions by recording the light absorbance for each solution atwavelengths of 276, 500, and 637 nm (depending on the brine con-centration) as a function of surfactant concentration before and afterequilibrium with shale fines. First, 2 g of shale fines (75 lm < diam-eter < 150 lm) were equilibrated with 15 g of surfactant solution byconstant shaking (300 strokes/minute) overnight. The absorbance of

Fig. 5. CMC of anionic surfactant in synthetic brine using (a) UV–Vis spectrometry and (b) pendant drop, and CMC of nonionic surfactant in reservoir brine using (c) UV–Visspectrometry and (d) pendant drop.

Fig. 6. Adsorption of surfactants on shale fines for Systems A and B. The linesrepresent the fit with Langmuir isotherm.

V. Mirchi et al. / Fuel 148 (2015) 127–138 133

surfactant solutions equilibrated with shale fines was analyzed andcompared to the calibration curve (i.e., surfactant absorbance curvewithout shale). The amount of surfactant adsorbed per gram of shalewas then calculated at different surfactant concentrations and aLangmuir isotherm [31] was used to model the adsorption data.Fig. 6 shows that the maximum adsorption amounts (Cmax) wereabout 12 and 3 mg/g for System A (5 M synthetic brine) and SystemB, respectively. Note that using tap water instead of reservoir brinedid not affect the surfactant adsorption in System B. In this system,Cmax was reached after the CMC. The interaction forces between thenonionic surfactant and Shale B are expected to be small. The mech-anism of interaction in this case is either through hydrogen bonding,polarization of p electrons, van der Waals dispersion forces or alter-nating hydrophobic bonding [32]. Unlike the nonionic surfactant,the adsorption of the anionic surfactant on Shale A is higher and doesnot reach a plateau even at 0.1 wt%, suggesting multilayer adsorp-tion. This is in agreement with a previous study by Grigg and Bai[33] who found that the adsorption density of an anionic surfactanton negatively charged sandstone increased by increasing NaCl con-centration in brine and in the presence of divalent cations.

5.3. Effect of temperature and pressure

5.3.1. Interfacial tensionA series of IFT experiments were performed with System A (5 M

synthetic brine) at both ambient (25 �C, 1 atm) and high P–T (80 �C,3000 psi). Fig. 7a shows that the IFT decreased by increasing

temperature and pressure, while the CMC remained unchanged.This decrease in IFT is mostly affected by the increase in tempera-ture [34]. Sharma et al. [35] stated that as temperature rises, thekinetic energy of molecules increases and consequently the attrac-tive forces between them drops leading to a reduction in IFT

134 V. Mirchi et al. / Fuel 148 (2015) 127–138

between surfactant solution and oil. This is also consistent withresults reported by other researchers [2,4,36].

5.3.2. Contact angleThe shale wettability was also examined with System A (5 M

synthetic brine) through contact angle measurements at ambientand high P–T conditions. Fig. 7b shows that an increase in temper-ature and pressure leads to relatively less water–wet conditions onthe shale surface, as CA increased. This trend is probably due to agreater adsorption of the anionic surfactant at high P–T in the pres-ence of electrolytes, making the surface less hydrophilic.

5.4. Effect of surfactant concentration

5.4.1. Interfacial tensionThe effect of surfactant concentration (up to 0.1 wt%) on IFT was

measured for both Systems A and B. For System A (5 M syntheticbrine) at high P–T (80 �C and 3000 psi), a sharp decline in IFT withsurfactant concentration was observed up to the CMC, as discussedin Section 5.1 and Fig. 5b. However for System B at reservoir con-ditions (116 �C and 6840 psi), the decline in IFT was not pro-nounced, as seen in Fig. 8a. An important point here is that usingtap water instead of reservoir brine has decreased the IFT byalmost 50%, while it has not changed the CMC. This indicates thatutilizing municipal water, for example, in fracturing fluids mayimprove the flow-back of oil after well stimulation by reducingthe resistance to flow and mobilizing more oil. Additional tests(e.g., imbibition) are required to assess the performance of thesesystems as there might be no direct correlation between IFT andoil recovery [37].

5.4.2. Contact angleThe impact of surfactant concentration (up to 0.1 wt%) on the

wettability of Shales A and B was also assessed through dynamiccontact angle measurements. Fig. 8b displays the dynamic CA ofSystem A (5 M synthetic brine) at high P–T (80 �C and 3000 psi).The contact angle in this case increased from �47� (without surfac-tant) to �70� at high surfactant concentration. The most significantwettability alteration (to less water–wet) occurred at concentra-tions above the CMC, possibly due to the increased surfactantadsorption on shale. Based on a previous study by Chaudhuri andParia [38], it is likely that surfactant molecules primarily adsorbvia their tails onto the negatively charged shale surface at low salin-ity due to Van der Walls attraction between the surfactant tailgroups and the negatively charged surface (cf. Fig. 9a). At high salin-ity, the interaction between cations in brine and the surfactant headgroups lowers their electrostatic repulsion. Hence, it is possible thatanother layer of surfactants adsorbs on the surface with their tailsfacing outward, which makes the surface more hydrophobic (cf.

(a)

Dyn

amic

con

tact

ang

le (d

egre

e)

Fig. 7. Effect of temperature and pressure on (a) IFT and (b) dynamic CA of System A

Fig. 9b). This is in agreement with the adsorption results in Section5.2.

For System B at reservoir conditions (116 �C and 6840 psi),there is no significant change in shale wettability using the non-ionic surfactant, as shown in Fig. 8b. In other words, the shale sur-face remains strongly water–wet regardless of surfactantconcentration. Moreover, CA data with reservoir brine and tapwater are analogous, within the experimental errors. This is inagreement with the negligible surfactant adsorption on shale mea-sured by UV–Vis spectroscopy (cf. Fig. 6). Therefore, we expect lowsurfactant losses due to adsorption on shale during hydraulic frac-turing with this surfactant. There are a number of experimentalstudies that report a reduction in contact angle when using non-ionic surfactants with negatively charged surfaces such as quartzand shale [20,39,40]. The reduction in CA was attributed to (i)stronger interactions between water molecules and quartz thanthose between surfactant molecules and quartz, and (ii) adsorptionof surfactant molecules with their hydrophobic tails facing theshale surface. The different trend observed in our study might bedue to a lower surfactant adsorption (�3 mg/g compared to10 mg/g in [20]), which is three to four times smaller than theadsorption of nonionic surfactant in these studies. A study on thewettability of Bakken shale using both anionic and nonionic surfac-tant solutions found that the wettability of the upper Bakkenshifted from oil–wet to neutral–wet and the wettability of the mid-dle Bakken changed from weakly oil–wet to neutral–wet [14]. Thediscrepancy between these studies and our work might be due todifferences in the mineralogy, pore types, composition of crudeoil, surfactant structure, and measurement techniques.

It could be argued that the decline in IFT of System B forinstance from 27 to 15 mN/m is expected to alter the contact angle.To answer this question, we refer to Young’s equation (cf. Fig. 10),in which the forces along the triple contact line are in thermody-namic equilibrium and are balanced according to:

cws ¼ cowcoshow þ cos ð2Þ

This study shows that the nonionic surfactant reduced oil–brineIFT, while contact angle was not notably altered. Since the surfac-tant was more soluble in brine than in oil, cws was likely todecrease while cos remained unchanged to satisfy the force balanceat the triple contact point. Therefore, the two sides of Eq. (2) can beadjusted without changing the contact angle.

5.4.3. Contact angle hysteresisDuring the dynamic contact angle measurements, the angle

obtained when oil displaced brine on shale was smaller than theone observed when brine displaced oil (cf. Fig. 11a). The differencebetween the two angles is called contact angle hysteresis and ismainly due to surface roughness, wettability alteration, and

(b)

10

20

30

40

50

60

70

80

0 0.01 0.03 0.05 0.1

Surfactant concentration (wt%)

AmbientHigh P-T

(5 M synthetic brine) at ambient and high P–T (3000 psi and 80 �C) conditions.

(b)(a)

10

20

30

40

50

60

70

80

0 0.01 0.03 0.05 0.1

Dyn

amic

con

tact

ang

le (d

egre

e)

Surfactant concentration (wt%)

System A [5 M NaCl]

System B [Tap water]

System B [Reservoir brine]

Fig. 8. Effect of surfactant concentration on (a) IFT and (b) dynamic CA for Systems A and B.

Fig. 9. Schematic diagram showing the orientation of anionic surfactant on shalesurface at (a) low salinity and (b) high salinity.

Fig. 10. Forces along the triple contact line in the Young equation.

V. Mirchi et al. / Fuel 148 (2015) 127–138 135

heterogeneity of solid surface [9]. Contact angle hysteresis directlyimpacts pore-level displacement mechanisms and the resultingmacroscopic multiphase flow functions.

The addition of surfactant into the system significantly reducedthe contact angle hysteresis from 10.06� (cf. Fig. 11a) to 0.42� (cf.Fig. 11b). A lower contact angle hysteresis implies that the energyrequired to overcome the local resistance to flow is lower andtherefore, an oil drop shrinks with essentially the same contactangle as it swells. This can have important implications for oil trap-ping in porous media and therefore for improved oil recovery.

5.5. Effect of brine chemistry

5.5.1. Interfacial tensionIn order to investigate the impact of brine chemistry on IFT of

Systems A and B, NaCl concentration in synthetic brines were var-ied from 0.1 to 5 M in System A, while for System B, the pH andsalinity of tap water were adjusted using HCl, KOH, NaCl, and

CaCl2. The surfactant concentration in brine was 0.1 wt% in bothsystems.

Fig. 12a reveals that the addition of salt to System A reduced theIFT between oil and brine. Similar behavior has been previouslyreported by other investigators [41–43] and attributed to a changein surfactant distribution at the oil/brine interface. Increasing saltconcentration makes the anionic surfactant less ionized and conse-quently less soluble in water, promoting more adsorption of sur-factant at the oil–brine interface [44].

For System B, we found that the IFT of crude oil and tap water(104 ppm TDS, pH�8) is lower than that of crude oil and reservoirbrine (237,340 ppm TDS, pH�4) (cf. Fig. 12a). This decline in IFTcould be explained by either the lower salinity or higher pH oftap water. In order to identify the dominant parameter in IFTreduction, the IFT between crude oil and tap water was measuredwhile independently varying its pH and salinity at ambient condi-tions (cf. Fig. 13). The results illustrated in Fig. 13a and b show thatboth salt addition and pH increase reduce the IFT, in agreementwith previous studies [44–46]. Thus, the lower IFT of tap watercompared to reservoir brine in Fig. 12a is likely due to the higherpH of tap water rather than its lower salinity.

5.5.2. Contact angleA series of dynamic contact angle measurements were per-

formed using the same systems as in Section 5.5.1. Fig. 12b showsthat CA in System A increased from 27.04� at 0.1 M to 69.94� at5 M, leading to a less water–wet shale surface. This trend couldbe correlated to the adsorption propensity of surfactant on shale,in accord with Sections 5.2 and 5.4.2 and other studies [33,47].Blunt [48] stated that for weakly water–wet systems with a con-tact angle lower than 90�, pore-body filling is the dominant dis-placement mechanism and the residual oil saturation decreaseswith increase in contact angle. Therefore, an increase in salinitycan potentially improve oil recovery from System A. The contactangles of System B did not change using either tap water or reser-voir brine (cf. Fig. 12b). This result is consistent with the lowadsorption tendency of nonionic surfactant observed in System B(Section 5.2) and suggests that the wettability of Shale B wouldnot be affected using tap water as injection fluid.

5.6. Work of adhesion

A better analysis of the experimental data can be achieved bycombining the IFT and CA results through the work of adhesion.The Young-Dupré equation (cf. Eq. (3)) relates the work of adhesion(Wa) to the surface tension between the fluids (c) and contact angleat the solid surface (h) [49].

(a) 0 wt% Surfactant A (b) 0.03 wt % Surfactant A

Fig. 11. Effect of surfactant concentration on contact angle hysteresis of System A (5 M synthetic brine): (a) without surfactant, (b) with 0.03 wt% Surfactant.

(b)(a)

0

2

4

6

8

10

12

14

16

18

HighLow

Inte

rfaci

al te

nsio

n (m

N/m

)

Salinity

System A

System B

0.1 M NaCl

5 M NaCl

Tap water

Reservoir brine

0

10

20

30

40

50

60

70

80

HighLow

Dyn

amic

con

tact

ang

le (d

egre

e)

Salinity

System A

System B

0.1 M NaCl

5 M NaCl

Tap water Reservoirbrine

Fig. 12. Effect of brine chemistry on (a) IFT and (b) dynamic CA of Systems A and B with 0.1 wt% surfactant.

Fig. 13. Interfacial tension between reservoir oil and tap water as a function of (a) pH (no salt added) and (b) salinity (pH�8) at ambient conditions.

136 V. Mirchi et al. / Fuel 148 (2015) 127–138

Wa ¼ cð1þ cos hÞ ð3Þ

This equation presents the work required to separate a drop ofliquid from a solid surface in the presence of another fluid.The calculated values of Wa in Systems A and B are listed inTable 7 for different surfactant and salt concentrations. In System

A, the lowest work of adhesion was achieved upon the additionof anionic surfactant (above CMC) in high salinity brine (5 M),which resulted in low IFT and high CA. Whereas in System B,the lowest Wa was achieved upon the addition of nonionic sur-factant (above CMC) in tap water, which resulted in a furtherIFT reduction.

Table 7Work of adhesion at various experimental conditions.

System A System B

Surfactant concentration, wt% 0.1 M 1 M 5 M Tap water Reservoir brine

0 – – 34.07 23.86 51.960.01 – – 23.01 22.36 –0.02 – – – – 36.660.03 – – 0.48 18.99 –0.05 – – 0.23 13.64 30.220.1 19.02 5.35 0.36 13.99 –

V. Mirchi et al. / Fuel 148 (2015) 127–138 137

6. Conclusions

A new framework was proposed to investigate the effect of pres-sure, temperature, surfactant concentration, and brine chemistry onfundamental parameters governing fluid displacement (i.e., interfa-cial tension and contact angle) in brine/oil/shale systems at reservoirconditions. The rising/captive bubble technique was first validatedwith simple surfactant systems by using very thin needles (i.e.,0.3 mm outside diameter) to reach Bond numbers close to unity.The ultra-low interfacial tensions obtained by this method werecomparable to those generated using the Spinning Drop technique.The method was further applied to two shale systems (A and B)and IFT values as low as 0.3 mN/m were measured at reservoir con-ditions. The main conclusions drawn from this study are summa-rized below:

1. Brine chemistry did not have any significant effect on the CMCof the nonionic surfactant used in this study. However, increas-ing brine salinity from 0.1 to 5 M decreased the CMC of anionicsurfactant from 0.05 to 0.03 wt% due to salting out effect.

2. The interfacial tension between oil and brine in System Areduced considerably (i.e., 23–0.3 mN/m) by introduction of0.03 wt% of anionic surfactant. On the other hand, the IFT valuesfor System B reduced only modestly (i.e., 27–15 mN/m) when anonionic surfactant was used at reservoir conditions.

3. The contact angle on Shale A samples increased by increasingbrine salinity and surfactant concentration particularly at highP–T as a result of high surfactant adsorption.

4. The nonionic surfactant showed a low propensity to adsorb onshale B samples. As a result, the shale surfaces remainedstrongly water–wet with the nonionic surfactant regardless ofsurfactant concentration and brine chemistry.

5. The lowest work of adhesion was achieved right above the CMCindicating that higher surfactant concentrations may not berequired.

6. The use of tap water instead of reservoir brine reduced IFT andwork of adhesion considerably.

Acknowledgements

We gratefully acknowledge the financial support from HessCorporation and the School of Energy Resources at the Universityof Wyoming. The Enhanced Oil Recovery Institute of the Universityof Wyoming is also thanked for providing crude oil A used in thisstudy.

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