Journal of Petroleum Science and Engineering 111 (2013) 128–138

Contents lists available at ScienceDirect

Journal of Petroleum Science and Engineering

0920-41http://d

n CorrE-m

lucker8

journal homepage: www.elsevier.com/locate/petrol

A coreflood investigation of nanofluid enhanced oil recovery

Luky Hendraningrat n, Shidong Li, Ole TorsæterDepartment of Petroleum Engineering and Applied Geophysics, Norwegian University of Science and Technology, NTNU, NO-7491, Trondheim, Norway

a r t i c l e i n f o

Article history:Received 31 January 2013Accepted 10 July 2013Available online 1 August 2013

Keywords:Enhanced oil recoverySilica nanoparticleNanofluidsStructural disjoining pressureBerea sandstone

05/$ - see front matter & 2013 Elsevier B.V. Ax.doi.org/10.1016/j.petrol.2013.07.003

esponding author. Tel.: +47 735 94 94; fax: +4ail addresses: luky.hendraningrat@ntnu.no,3@gmail.com (L. Hendraningrat).

a b s t r a c t

Recently nanoparticles have become an attractive agent for improved and enhanced oil recovery (IOR &EOR) at laboratory scale. Most researchers have observed promising results and increased ultimate oilrecovery by injecting nanoparticle suspension (nanofluid) in laboratory experiments. The objective ofthis study is to reveal nanofluid possibility for EOR in low to high-permeability sandstone (ss) rocks andinvestigate suitable concentration. In this study, parameters involved in the structural disjoining pressuremechanism, such as lowering interfacial tensions (IFT) and altering wettability, were studied. Laboratorycoreflood experiments were performed in water-wet Berea ss core plugs with permeability in range9–400 mD using different concentrations of nanofluids. A crude oil from a field in the North Sea wasemployed and three nanofluid concentrations 0.01, 0.05 and 0.1 wt% were synthesized with syntheticbrine. We observed that IFT decreased when hydrophilic nanoparticles were introduced to brine. The IFTdecreases as nanofluid concentration increases and this indicates a potential for EOR. Increasinghydrophilic nanoparticles will also decrease contact angle of aqueous phase and increase water wetness.We have also observed that the higher the concentrations of nanofluids, the more the impairment ofporosity and permeability in Berea core plugs. Despite that increasing nanofluid concentration showsdecreasing IFT and altering wettability, our results indicate that additional recovery is not guaranteed.The processes and results are outlined and also further detailed in the paper to reveal the possibleapplication of nanofluid EOR as a future or an alternative EOR method.

& 2013 Elsevier B.V. All rights reserved.

1. Introduction

Most of the oil fields around the world have reached or willreach soon the phase where the production rate is nearing thedecline period. Hence, the current main challenge is how to delaythe abandonment by extracting more oil economically. The latestworldwide industries innovation trends are miniaturization andnanotechnology materials. Nanotechnology is defined as the con-struction of functional materials, devices, and systems by control-ling matter at the nanoscale level (one-billionth meter), and theexploitation of their novel properties and phenomena that emergeat that scale (Das et al., 2008).

A nanoparticle, as a part of nanotechnology, has size typicallyless than 100 nm. It is composed of two entities: the core and athin shell (Das et al., 2008). The core and shell may have under-lying structures and may be composed of more than one entity.The molecular shell has three separate regions: tail group, hydro-carbon chain and active head group, although one or more of thesemay be absent in a specific case (see Fig. 1). A hydrocarbon chainmay be long, as in a polymer, or completely absent, as in an ion,

ll rights reserved.

7 739 44 472.

protecting the nanoparticle (Das et al., 2008). The shell may alsobe an extended solid, such as silicon dioxide (SiO2), that we used inthis study. The chemical nature of a shell will determine thesolubility of nanoparticles such as lipophobic and hydrophilicnanoparticles (LHP) dissolved in polar solvent such as water, andhydrophobic and lipophilic nanoparticle (HLP) dissolved in non-polar solvents such as toluene.

Nanofluid is defined as nanoparticle that has an average size lessthan 100 nm, suspended in traditional heat transfer fluid such aswater, oil or ethylene glycol (Das et al., 2008). Nanofluid technology,as a part of nanotechnology, is a new interdisciplinary area of greatimportance where nanoscience, nanotechnology, and thermal engi-neering come across. It has developed largely over the past decadeand revealed its potential applications in oil and gas industries.Through continuously increasing publications addressed on the topic,it has motivated us to investigate the possibility of nanofluids as afuture or an alternative improved/enhanced oil recovery method.

2. Displacement mechanism

Oil recovery possible mechanism using nanoparticles suspen-sion has been experimentally investigated by Wasan and Nikolov(2003), Chengara et al. (2004), and Wasan et al. (2011) and calledstructural disjoining pressure mechanism. Later, Mc.Elfresh et al.

Fig. 1. Illustration (not to scale) of nanoparticle schematic (from Das et al., 2008) and structural disjoining pressure gradient mechanism among solid, oil and nanofluids asaqueous phase due to nanoparticles structuring in the wedge-film (from Wasan et al., 2011).

Fig. 2. Residual oil inside pore network of glass micromodel under microscope 5� : (a) situation after imbibition process with brine and (b) situation after injectingnanofluids 0.1 wt% as tertiary recovery process. Residual oil was decreasing after injecting nanofluids at 0.2 cm3/min.

L. Hendraningrat et al. / Journal of Petroleum Science and Engineering 111 (2013) 128–138 129

(2012) described the energies that drive this mechanism asBrownian motion and electrostatic repulsion between the nano-particles. The electrostatic repulsion force between those particleswill be bigger when nanoparticle size is smaller. When the amountof the nanoparticles is increasing, the force will increase.

The presence of these nanoparticles in three-phase contactregion has a tendency to create a wedge-film structure. Structuraldisjoining pressure is correlated to the fluids ability to spreadalong the surface of a substrate due to imbalance of the interfacialforces among solid, oil phase and aqueous phase (Chengara et al.,2004). The interfacial forces will cause aqueous phase (nanofluid)contact angle (θ) to decrease to 11 and the result is a wedge film.This wedge film will act to separate formation fluid such as oil,paraffin, water and gas from the formation surface (Mc.Elfreshet al., 2012).

Driven by the aqueous pressure of the bulk liquid, the nanofluidis able to spread along the surface as monolayer particles.Completely spreading occurs when the contact angle is zero.Wasan and Nikolov (2003) observed that the driving force forthe spreading of the nanofluids is the structural disjoining pres-sure (film tension) gradient (Δγ) directed towards the wedge fromthe bulk solution. The film tension is high near the vertex becauseof the nanoparticle structuring in the wedge confinement. It drivesthe nanofluids to spread at the wedge tip as the film tensionincreases towards the vertex of the wedge. They also investigatedthat spreading coefficient increases exponentially with a decreasein the film thickness or decrease in the number of particle layers

inside the film. As the film thickness decreases towards the wedgevertex, the structural disjoining pressure increases.

In our preliminary two-phase flow EOR study using transparentglass micromodel (porosity 44% and permeability 25 D) showedthat nanofluids 0.1 wt% could reduce residual oil saturation asshown in Fig. 2. However, this porous medium has very highporosity and permeability and does not represent common oilreservoir rocks. Previous coreflood experiment using water-wetBerea ss with average porosity 23% and permeability 375 mD andsynthetic oil with viscosity 2 mPas showed that nanofluids withvery low concentration 0.01 wt% could enhance oil recoveryalmost 2% points (Hendraningrat et al., 2012). Hence, the goal inthis study is to broadly reveal the possibility of using nanofluids asan EOR method in low to high-permeability rocks and investigateits suitable nanofluid concentration.

3. Materials

3.1. Nanoparticle

A LHP with single particle size 7 nm, dominantly most dis-tributed in range 21–40 nm and consists more than 99.8% ofsilicon dioxide (SiO2), has been used in this study. Other minorelements are aluminum oxide (Al2O3)r0.05%, titanium dioxide(TiO2)r0.03%, hydrogen chloride (HCl)r0.025% and ferric oxide(Fe2O3)r0.003%. It has acidity with the pH range from 3 to 5.

Fig. 3. Nanoparticles characterization under SEM (magnification 450k times) with nanoparticles distribution analysis using nanosight (based on dynamic light scatteringmethod).

Table 1Fluid properties.

Fluid Density Viscosity pH Temperature(g/cm3) (mPa. s) (1C)

Brine, NaCl 3 wt% 1.022 1.001 6.76 21.4Nanofluid 0.01 wt% 1.012 1.006 6.26 21.7Nanofluid 0.05 wt% 1.015 1.010 6.16 21.2Nanofluid 0.1 wt% 1.017 1.015 5.25 20.0Crude oil 0.826 5.10 – 22.0

Table 2Dimensions and average petrophysical properties at initial condition.

Berea ss no. Length Diameter Porevolume

Porosity Avg. liq.permeability

(mm) (mm) (cm3) (%) (mD)

L1 40.83 37.98 7.03 15.02 13L2 40.73 37.96 6.42 13.93 9L3 41.05 37.94 7.13 15.37 35L4 40.75 37.92 6.70 14.55 20L5 41.04 37.84 6.88 14.90 18L6 40.08 37.95 6.49 14.10 10H1 48.34 37.93 12.67 23.20 392H2 48.09 37.92 12.41 20.01 156H3 48.12 37.91 12.52 23.04 302H4 48.02 37.90 12.42 22.93 354

L, low-permeability; H, high-permeability.

L. Hendraningrat et al. / Journal of Petroleum Science and Engineering 111 (2013) 128–138130

The specific surface area of LHP is 300 m2/g. The LHP has beencharacterized under Zeiss Supra 55 VP low vacuum ScanningElectron Microscope (SEM) with a scale of 200 nm and nanopar-ticle distribution dispersed in brine through Nanosight measure-ment as shown in Fig. 3.

3.2. Fluids

In this study, a degassed crude oil from a field in North Sea hasbeen employed. It has density and viscosity of 0.826 g/cm3 and5.10 mPas, respectively. Synthetic reservoir brine was made as abase fluid solution between sodium chloride (NaCl) 3.0 wt% anddeionized water. The density of brine was 1.02 g/cm3, viscosity1.0 mPas and pH 6.76 at 21.4 1C. The density and viscosity weremeasured using pycnometer and Brookfield viscometer, respec-tively. This brine was also used as dispersed fluid for thesenanoparticles. The reason is that brine is present in oil reservoirsand easily available in offshore fields. The most important LHPnanoparticles can easily be dispersed in water-based fluid such asbrine. Nanofluids with various weight concentrations 0.01, 0.05and 0.1 wt% were synthesized using high speed magnetic stirringfor 3–4 min and continued with sonicator at 40–100% amplitudefor 3–5 min. Table 1 shows fluid properties measurement of brineand various nanofluid concentrations at ambient condition.

3.3. Porous medium

Several water-wet Berea ss core plugs with the range ofpermeability from 9 to 400 mD were used in this study. First, coreplugs were cleaned using toluene through soxhlet extractionapparatus at 65–70 1C for 6 h. Cleaning with methanol throughsoxhlet extraction at similar condition and duration followed. The

core plugs were heated in the oven at 70 1C for 6 h. The dryweight, length, diameter and porosity were measured. Heliumporosimeter and liquid Hassler permeameter were used to mea-sure porosity and permeability, respectively. The measured dimen-sion and average petrophysical properties at initial condition arelisted in Table 2.

Pore size of core plugs has been observed under SEM. Crockeret al. (1983) have investigated that average pore size for Berea ss(porosity 19.2% and permeability 302 mD) is 18 mm. Based on ourobservation as shown in Fig. 4b, the pore size of low–mediumpermeability seems to be at a glance less than 10 mm. Meanwhile,higher permeability pore size shows higher pore size around25–30 mm from Fig. 4d.

4. Method

4.1. Coreflood setup

The experiment aims to reveal nanofluids possibility for EOR inlow to high permeability of sandstone reservoir rocks and inves-tigate suitable nanofluid concentration. Hence various nanofluidswere injected as tertiary recovery mode after brine flooding atroom temperature. The injection rate was kept constant at0.2 cm3/min. Figs. 5 and 6 show experimental instruments andschematic of coreflood setup, respectively. The pump injected

Fig. 4. (a) Low–medium permeability Berea ss with its pore size morphology under SEM (b); and (c) higher permeability Berea ss with its pore size morphology under SEM (d).

Fig. 5. Experimental instruments.

L. Hendraningrat et al. / Journal of Petroleum Science and Engineering 111 (2013) 128–138 131

exxol D-60 as pump fluid from bottle through 1/8 in. pipe to pushthe piston plate located inside the vessel. The piston plate is alsouseful to separate between different fluids in the similar cylinderwithout mixing.

There are three different vessels installed with piston plate ineach vessel. Those vessels were filled up each with brine, crude oiland nanofluid. Valves were installed at inlet and outlet of thevessel to regulate fluid flow. There is a bypass flowline to clean the

line before injecting another fluid. The influent flowlines fromvessels are connected to Hassler core holder. The sleeve pressurewas set to 20 bar in the Hassler core holder. Oil flowline at vessel’soutlet is separated from others vessel’s outlet to minimize earlymixing of those fluids. The differential pressure was recorded byprecision pressure gauge (range 0–3 bar) that is connected to thePC monitor. The accumulator tubes were prepared to measure theeffluent from core during flooding process.

4.2. Coreflood procedure

The core plug dimensions and dry weight were obtained. Thenthe core plugs were fully saturated with brine using a vacuumcontainer for approx. 1–2 h at a pressure of 0.1 bar. The corefloodinstrument was setup as shown in Fig. 6. The sleeve pressure wasset at 20 bar into core cell. There were single-phase and two-phaseflow coreflood experiments. Single-phase flow (brine/nanofluid)was performed for porosity and permeability impairment withinjection rate from 0.1 to 0.5 cm3/min. Meanwhile for two-phase flow,the drainage process was started by injecting degassed crude oil withrate from 0.2 to 1.0 cm3/min until surely no more brine produced. Toreach this situation it required about 3–10 PV injection. The initialwater saturation was established. As a first imbibition process, brinewas injected at constant rate 0.2 cm3/min approx. 3–5 PV until surelyno more oil produced and thereby residual oil saturation wasestablished. Then the injection was continued at constant rate

Fig. 6. Schematic of experimental setup: (1) pump fluid (exxol D-60), (2) injection line, (3) micro-pump, (4) valve, (5) pump fluid in vessel-A, (6) piston plate, (7) brine invessel-A, (8) oil in vessel-B, (9) nanofluid in vessel-C, (10) oil line, (11) brine/nanofluid line, (12) bypass valve, (13) hassler core cell, (14) core plug inside cell, (15) pressuregauge, (16) sleeve pressure, (17) connection cable, (18) computer, (19) accumulator.

Table 3Saturation process and EOR scenarios.

Berea ss no. PV injected atdrainage process

Initial watersaturation

Initial oilsaturation

PV injected at imbibitionprocess with brine

Oil saturation afterbrine Injection

Nanofluids concentrationfor EOR scenario

(%) (%) (%) (wt%)

L1 6.1 18.94 81.06 3.4 35.98 0.01L2 4.7 15.89 84.11 3.2 53.74 0.01L3 7.0 20.06 79.94 3.0 34.36 0.05L4 7.5 20.90 79.10 2.7 34.70 0.05L5 7.3 31.67 68.33 3.3 25.81 0.1L6 10.8 26.03 73.97 5.2 37.75 0.1H1 3.9 15.56 84.44 3.7 41.04 0.01H2 4.0 24.25 75.75 3.0 29.01 0.05H3 4.0 23.29 76.71 3.2 27.57 0.05H4 3.2 24.34 75.66 3.1 37.43 0.1

L, low-permeability; H, high-permeability.

Fig. 7. Crude oil drop shape from SVT20 spinning drop video tensiometer. Exampledrop for system crude oil-nanofluid 0.05 wt% and crude oil.

L. Hendraningrat et al. / Journal of Petroleum Science and Engineering 111 (2013) 128–138132

0.2 cm3/min approx. 3–4 PV of nanofluid as tertiary recovery mode.There are three different nanofluid concentrations 0.01; 0.05 and0.1 wt%. The oil recovery performance and decreased residual oilsaturationwere evaluated. Table 3 shows howmany PV were injectedduring drainage, imbibition process using brine flooding and nano-fluids EOR scenario.

4.3. Interfacial tension measurement

The interfacial tension (IFT) between degassed crude oil andbrine/nanofluids as aqueous phase was measured by using SVT20

spinning drop video tensiometer around 1 h at ambient condition(Fig. 7). The drop volume was in range 2–3 mL. The rotation speedwas kept around 5000–6000 rpm. The formula to measure IFT is asfollows (Than et al., 1988):

s¼ Δρ:Ω2:ðDappÞ38n3JDðL=DÞ

ð1Þ

where s is the interfacial tension (dyn/cm), Δρ is the densitydifference (g/cm3), Ω is the rotational rate of the cylinder (s�1),Dapp is the measured drop diameter (cm), n is the refractive indexof the heavy fluid, D is the true diameter of the drop (D¼Dapp=n),JD is the correction factor and function of L/D, and L/D is the aspectratio (e.g. the ratio of the drop length to its diameter).

As an input data, refractive index was measured using refract-ometer Mettler Toledo for all aqueous phases and summarized inTable 4. The refractive index slightly increases as nanofluid concentra-tion increases.

4.4. Contact angle measurement

Contact angle, θ, is a quantitative measurement of the wettingcharacteristic of a solid by a liquid and defined geometrically asthe angle formed by a liquid at the three-phase boundary where aliquid, gas (lighter) and solid intersect. Low value of θ indicatesthat the liquid spreads or wets. Otherwise high value indicatespoor wetting. Treiber et al. (1971) defined contact angle in 3-phasesystem (water, oil and rock surface) as follows: water-wet in therange from 01 to 751, intermediate/neutral-wet in the range751–1051 and oil-wet in the range 1051–1801. A zero contact anglerepresents that the denser fluid is completely wetting the solid.

Fig. 8. Contact angle formation on polished synthetic silica between crude oil andbrine/nanofluids according to the Young formula.

Fig. 9. Interfacial tension and contact angle measurement for crude oil againstbrine with various nanofluid concentrations at ambient condition.

Table 4Refractive Index for aqueous phase.

Fluid Average Temperature(n) (1C)

Deionized water 1.33100 20.1Brine, NaCl 3 wt% 1.33624 19.9Nanofluid 0.01 wt% 1.33612 20.2Nanofluid 0.05 wt% 1.33646 20.8Nanofluid 0.1 wt% 1.33662 20.5

L. Hendraningrat et al. / Journal of Petroleum Science and Engineering 111 (2013) 128–138 133

In this experiment, contact angle was measured directly onpolished synthetic silica using Goniometry KSV CAM instrument atroom condition. The system consists of crude oil, brine/nanofluidsand polished synthetic silica (see Fig. 8). The measurement isbased on the Young formula as follow:

ss ¼ ssl þ sl: cos θ ð2Þwhere s describes interfacial tension components of phase, indicess and l stand for solid and liquid phases, ssl represents theinterfacial tension between the two phases and θ is the contactangle corresponding to the angle between vectors sl and ssl.

4.5. Mineral analysis and entrapped particle observation

The mineral element analysis was done on core plug P2 thathas been taken from similar large slab of water-wet high-perme-ability Berea ss. The analysis was done using energy dispersive X-ray spectroscopy (EDX). This method is based on the energydispersed by X-ray beam and reflects of surface localizations ofthe object mineral (Lake, 1989). There are two purposes ofperforming mineral analysis here: to characterize minerals includ-ing clay and nanoparticles in core plugs and to distinguishbetween nanoparticle and other mineral.

To analyze porosity and permeability impairment, entrappednanoparticles inside porous medium were observed in two differ-ent ways. Firstly, microscopic visualization under SEM was per-formed to see any nanoparticles retention inside core plug bycutting it, both in wet and dry conditions. Secondly, it wasindicated from differential pressure log-jamming during single-phase coreflood experiment.

Permeability is an important property of the porous medium,and it is a measure of capacity of the medium to transmit fluids. Itis a tensor that in general is a function of pressure (Torsæter andAbtahi, 2003). Examination of permeability impairment was con-ducted by comparing the flow ability of brine into core plugs pre-and post-nanofluid injection. By knowing all parameters, andrecording ΔP, Darcy’s equation was used to calculate the

permeability of pre- and post-nanofluid injection:

qA¼ k

ml

ΔPL

ð3Þ

where k is the permeability of medium (m2), q is the flowrate (m3/s),L is the length of pore medium from the inlet to the outlet (m), m isthe viscosity of phase ‘l’(Pa s), ΔP is the differential pressure betweenhigh pressure and low pressure (Pa) and A is the cross-sectional areato flow (m2).

We define average percentage liquid permeability impairmentin this study as follows:

kimp ¼ðkpost�kpreÞ � 100

kpreð4Þ

5. Results and discussion

5.1. Effect of LHP silica nanofluids on IFT and contact angle

In this study, parameters involved in the disjoining pressuremechanism, such as lowering IFT and altering wettability, arestudied. An assessment of the relationship between interfacialtension, wettability and oil recovery in low–medium permeabilitywater-wet Berea ss due to the presence of LHP silica nanoparticlesis performed.

Introducing silica LHP nanoparticles into the brine–oil systemwas observed to give lower IFT and the decrease might be largeenough to produce more oil. Buckley and Fan (2005) reported IFTimpacts on capillary pressure, capillary number, adhesion tension,and the dimensionless time for imbibition. The capillary numberincreased with decrease of IFT and consequently some residual oilis mobilized.

Fig. 9 shows IFT measurement of crude oil against brine/nanofluids at various concentrations. IFT of brine–crude oil systemis 19.2 mN/m and is considered as a reference value. A LHP silicananoparticle has the ability to decrease IFT at the oil–brine inter-face and the value was about half of the reference value at aconcentration of 0.01 wt%. The interfacial tension is sensitive tonanofluid concentration. As we can see, IFT decreases as nanofluidconcentration increases. We are unsure with the result whenmeasuring at higher nanofluid concentrations than 0.05 wt%.However, pH of LHP silica nanofluids will decrease with increasedconcentrations of nanoparticles (see Table 1). The pH significantlydecreased from around 6 to 5 when nanofluid concentrationincreased from 0.05 to 0.1 wt%. The effect of aqueous phase’s pHin IFT oil–water system has been investigated by Buckley and Fan

L. Hendraningrat et al. / Journal of Petroleum Science and Engineering 111 (2013) 128–138134

(2005). They reported below pH of 6, the trend showed that IFTwould likely decrease for pH reduction from 6 to 3. Hence, it isexpected that the IFT for 0.1 wt% will follow the decline trend.

Owens and Archer (1971) reported that increasing the waterwetness increases ultimate oil recovery. Morrow (1990) observedalso that oil recovery decreased with decreasing water wetness.These results are consistent with the intuitive notion that strongwetting preference of the rock for water and associated strongcapillary imbibition forces give the most efficient oil displacement(Morrow, 1990). However, Cooke et al. (1974) observed thatincreasing oil-wetness increases oil recovery. Morrow (1985) alsoobserved that oil recovery was maximum for cores at intermediatewettability, which is probably related to disconnection and trap-ping of oil phase. Hence wettability has a vital role in crude oilproduction (Morrow, 1990) and determines the recovery efficiencyof displacement processes. Wettability affects both the distributionof hydrocarbon and aqueous phases within the rock matrix anddynamics of displacement processes (Fletcher, 2012).

Contact angle is the most universal measurement of thesurfaces wettability and an approach to measure reservoir wett-ability (Morrow, 1990). Figs. 9 and 10 show contact angle mea-surements of crude oil and brine/nanofluids at variousconcentrations on polished synthetic silica. Nanoparticles reducecontact angle of aqueous phase and consequently result in smallhysteresis.

The trend showed that increased hydrophilic silica nanofluidconcentration will increase water wetness. The electrostatic repul-sion force between the particles will be bigger when the amountof nanoparticle is huge. Driven by aqueous pressure of the bulkliquid, nanofluid will spread along the solid surface and decreasecontact angle.

Table 5Chemical compositions of common clay minerals in sandstone.

Clay type Chemical compositions

Kaolinite Al2Si2O5(OH)4Smectite (Na,Ca)0.33(Al,Mg)2(Si4O10)Chlorite NaClO2 or Mg(ClO2)2Illite (K,H3O)(Al,Mg,Fe)2(Si,Al)4O10[(OH)2,(H2O)]

5.2. Mineral analysis of Berea core plugs

The most common types of clay mineral deposited in sandstonereservoirs are kaolinite, smectite, illite and chlorite (Grim, 1953).The chemical compositions of clay minerals are shown in Table 5.There are only illite and kaolinite that do not swell and they willnot induce permeability impairment (Abbasi et al., 2011). Fig. 11ashows a random area of core P2 which consists of major clay andFig. 11b shows element minerals from EDX spectrum. As we cansee, there are some elements detected besides Si and O as matrixminerals: K, Fe, and Al. Based on Table 5, most of the clay mineralshave element Al, but only illite has all of them. Therefore, thepresence of K and Fe ensures that we have illite that is well-knownas non-expanding clay.

To distinguish between nanoparticle (LHP) and clay mineral,we took an image from core plug P4 as shown in Fig. 12. Asmentioned in the Material section, this LHP was created fromSiO2Z99.8%, Al2O3r0.05%, TiO2r0.03%, HClr0.025% andFe2O3r0.003%. The EDX instrument could only interpret mineral

Fig. 10. Contact angle measurement (flipped image) for crude oil agains

that consists of minimum 1%, therefore we needed a specificmineral such as Aluminum (Al).

As can be seen in Fig. 12a and b, mineral ‘Al’ and ‘K’ composi-tion line increased significantly when the area is shifted from red(suspected nanoparticles) to green (suspected non-nanoparticles).Therefore, we can be certain that red area is dominated withnanoparticles. In addition, element ‘K’ is identified as a part of clayminerals.

5.3. Effect of nanofluid concentration to porosity and permeabilityimpairment

Several separated injection scenarios for rock propertiesimpairment purposes have been performed in two sister coresand summarized in Table 6. The second method to find out thisimpairment was the differential pressure observation. It wasrecorded from core plugs P3 and P4 during single-phase flooding.Each of them was injected with different nanofluid concentrations0.01 wt% and 0.05 wt% as shown in Fig. 13. Brine 3 wt% NaCl wasinjected first into both core plugs for 0.2 PV at constant injectionrate 0.1 cm3/min. Then they were injected with nanofluids at thesame pore volume. At last, the brine was re-injected to observeany alteration after nanofluid flooding by comparing with theprofile before nanofluids injection. It was observed that theaverage differential pressure almost does not change after inject-ing 0.2 PV nanofluid 0.01 wt%. Otherwise, the average differentialpressure increased 71 mbar after injecting around 0.2 PV nano-fluid 0.05 wt%. The noise that occurred around 2 mbar was due topump stroke.

The porosity impairment is defined here as differentialbetween pre- and post-nanofluid injection. All core plugs thatwere re-measured after nanofluid injection showed porosityreduction even though they have been cleaned using soxhletextraction with methanol and dried in heating cabinet. Based onour observation, porosity and permeability impairment is clo-sely related with nanofluid concentration and volume ofinjected nanofluid. The higher nanofluid concentration willincrease the possibility of porosity and permeability impair-ment (see Tables 6 and 7).

t brine with various nanofluid concentrations at ambient condition.

Fig. 12. Surface morphology (a) and EDS spectrum (b) of core plug P4 to differ between nanoparticle and clay under SEM with magnitude 2000 times.

Fig. 11. Surface morphology (a) and EDS spectrum (b) of core plug P2 for clay mineral characterization under SEM with magnitude 253 times.

Table 6Helium porosity measurement: comparison between pre- and post-nanofluid injection.

Berea ss no. Porosity Porosity impairment Scenario

Pre Post (%)(%) (%)

P1 18.68 16.67 �2.01 Injected 3 PV nanofluid 0.5 wt% @ Qinj 0.5 cm3/minP2 18.75 16.63 �2.12 Injected 3 PV nanofluid 0.1 wt% @ Qinj 0.5 cm3/minP3 19.23 18.69 �0.54 Injected 0.2 PV nanofluid 0.05 wt% @ QInj 0.1 cm3/minP4 20.64 20.37 �0.27 Injected 0.2 PV nanofluid 0.01 wt% @ Qinj 0.1 cm3/min

L. Hendraningrat et al. / Journal of Petroleum Science and Engineering 111 (2013) 128–138 135

5.4. Differential pressure profile during two-phase corefloodexperiment

The differential pressure was recorded by precision pressure gaugeKeller PD-33X with range 0–3 bar. Unfortunately, differential pressurewas stopped recording for all low–medium permeability core plugswhen it reached almost the maximum limit after around 0.5 PV.Fig. 14 shows the differential pressure for core plug L2 that hasporosity 14% and permeability 9 mD. It was injected 3 PV with brineuntil no more oil was produced and continued with nanofluid 0.01 wt% as tertiary mode at constant rate 0.2 cm3/min.

Fig. 15 shows the differential pressure for core plug H2. UnlikeL2, the pressure for H2 was completely recorded during floodingprocess. It has porosity 20% and permeability 156 mD. It wasinjected 3 PV with brine until no more oil produced and continuedwith nanofluid 0.05 wt% as tertiary mode at constant rate0.2 cm3/min. In the first 0.5 PV brine flooding, 2-phase flow

existed and increased differential pressure was observed. Oncebrine breakthrough and only brine produced from core plugs,differential pressure goes down and stabilized at about 33 mbar.There was no more oil produced after 1 PV brine flooding and theinjection was stopped at 3 PV. About 3 PV of nanofluid injection incore plug H2. The differential pressure increased when nanofluidwas injected to this core plug. The reason may be that somenanoparticles adsorbed and blocked pore throats and therebyaltered rock and fluid properties including wettability and inter-facial tension. Nanofluid flooding needs around 1 PV to enhanceoil recovery. The final increase in oil recovery for core plug H2 isabout 5–6% points.

5.5. Effect of LHP silica nanofluids on oil recovery

Effects of introducing LHP silica nanofluids that altered wett-ability and interfacial tension on oil recovery have been

L. Hendraningrat et al. / Journal of Petroleum Science and Engineering 111 (2013) 128–138136

investigated through laboratory coreflood displacement test onseveral core plugs with low–medium and high permeability andplotted in Figs. 16 and 17. All the results have been tabulated inTable 8. The oil recovery after brine injection is in the range 36–62% of OOIP for low–medium permeability and the trend isincreasing oil recovery with increased rock permeability. Mean-while higher permeability core plugs have 50–64% recovery ofOOIP after brine flooding.

Nanofluids were injected around 3 PV at constant injection rate0.2 cm3/min and around 0.5–1 PV were needed to start displacingmore oil. Displacement efficiency due to nanofluids has beenevaluated and summarized in Table 8. The displacement efficiencyof nanofluids calculated here follows the formula below:

ED ¼ 1� Sor2Sor1

� �� �:100 ð5Þ

where Sor1 represents the residual oil saturation after brine injectionand Sor2 represents the residual oil saturation after nanofluidsfor EOR.

We observed that displacement efficiency is higher whennanofluid concentration is increased from 0.01 to 0.05 wt% bothin low–medium permeability and high-permeability core plugs.The residual oil saturation decreases when nanofluid concentra-tion is increased for low-permeability core plugs (Figs. 18–20).The reduction of residual oil saturation was less than 5%points. Consequently, the ultimate oil recovery increases as thenanofluid concentration increases from 0.01 to 0.05 wt% but therecovery is less than 70% oil recovery. Compared to low–medium

Table 7Liquid permeability measurement: comparison between pre- and post-nanofluid inject

Berea ss no. Avg. liq. permeability Avg. liq. permea

Pre Post (%)(�10�3 mm2) (�10�3 mm2)

P1 – 18.89 –

P2 346.92 44.21 �87.99P3 224.67 189.20 �15.80P4 223.15 210.02 �5.90

Fig. 13. Differential pressure profile during brine and nanofluid flooding from twosister core plugs P3 and P4 (single-phase).

permeability, additional oil recovery due to nanofluids is higher inhigh-permeability core plugs at given nanofluid concentration.

There was no additional oil recovery in low–medium perme-ability reservoir and less oil recovery in high-permeability rockswhen nanofluid concentrations increased to 0.1 wt%. Based onthe previous observation, this was caused by particles blocking thepore network rather than displacing more oil. Overall, thenanofluid concentration at 0.05 wt% is the best among otherconcentrations in this study on oil recovery both for low–mediumand high-permeability water-wet Berea ss core plugs. In addition

ion.

bility impairment Scenario

Injected 3 PV nanofluid 0.5 wt%: Qinj 0.5 cm3/minInjected 3 PV nanofluid 0.1wt%: Qinj 0.5 cm3/minInjected 0.2 PV nanofluid 0.05 wt%: Qinj 0.1 cm3/minInjected 0.2 PV nanofluid 0.01 wt%: Qinj 0.1 cm3/min

Fig. 14. Oil recovery performance, differential pressure vs. injected PV of core L2:imbibition and EOR process with nanofluids 0.01 wt% at constant injection rate0.2 cm3/min.

Fig. 15. Oil recovery performance, differential pressure vs. injected PV of core H2:imbibition and EOR process with nanofluids 0.05 wt%.

L. Hendraningrat et al. / Journal of Petroleum Science and Engineering 111 (2013) 128–138 137

its displacement efficiency is also the highest for all types ofpermeability of the core plugs. In further, optimum nanofluidconcentration will be studied to get maximum oil recovery fromnanofluids EOR.

Further works are necessary to establish the connectionbetween these results and relative permeability curves. It is alsonecessary to perform experiments on core plugs with differentwettabilities (neutral-wet and oil-wet). In addition, silica nano-particles associated with appropriate surfactant are a possible nextresearch step. Hopefully, surfactants will give smaller interfacialtension and remove fluid such as oil, paraffin and polymer

Fig. 16. Oil recovery performance vs. injected PV for low–medium permeabilitycore plugs with various nanofluid concentrations.

Fig. 17. Oil recovery performance vs. injected PV for high-permeability core plugswith various nanofluid concentrations.

Table 8Oil recovery due to brine and EOR with nanofluids at various concentrations and displacement efficiency at constant injection rate 0.2 cm3/min.

Berea ssno.

Oil saturationafter brineinjection(Sor1), %

Oil recovery afterbrine injection, %OOIP

Nanofluidsinjection forEOR scenario(wt%)

PV injected atEOR process withnanofluids

Oil saturation afternanofluidsInjection (Sor2), %

Ultimate oilrecoveryafter nanofluids, %OOIP

Displacementefficiency ofnanofluids, ED %

L1 35.98 55.61 0.01 2.7 33.84 58.25 5.93L2 53.74 36.11 0.01 3.1 52.18 37.96 2.90L3 34.36 57.02 0.05 3.0 29.45 63.16 14.29L4 34.70 56.13 0.05 3.4 32.31 59.15 6.88L5 25.81 62.23 0.1 2.8 25.81 62.23 0.00L6 37.75 48.96 0.1 3.0 37.75 48.96 0.00H1 41.04 51.40 0.01 2.8 37.09 56.07 9.62H2 29.01 61.70 0.05 3.1 24.98 67.02 13.89H3 27.57 64.06 0.05 3.1 23.97 68.75 13.04H4 37.43 50.53 0.1 3.5 34.21 54.79 8.60

L, low-permeability; H, high-permeability.

Fig. 18. Reducing residual oil saturation with nanofluids 0.01 wt%. Both low–

medium and high-permeability core plugs decrease residual oil saturation.

Fig. 19. Reducing residual oil saturation with nanofluids 0.05 wt%. Both low–

medium and high-permeability core plugs decrease residual oil saturation.

Fig. 20. Reducing residual oil saturation with nanofluids 0.1 wt%. Only in the high-permeability core plug decreases residual oil saturation.

L. Hendraningrat et al. / Journal of Petroleum Science and Engineering 111 (2013) 128–138138

residues and thereby make the substrate water-wet as mentionedby Mc.Elfresh et al. (2012).

6. Conclusions

Based on the experimental results, the following conclusionscan be stated:

1.

Lipophobic and hydrophilic nanoparticles (LHP) silica nanopar-ticle have the ability to reduce the interfacial tension betweenoil-aqueous system and contact angle of aqueous phase. Theinterfacial tension and contact angle decrease when nanofluidconcentration increases.

2.

Based on the mineral element analysis, the core plugs mightcontain clay mineral type illite that is well-known as non-expanding clay. Therefore, the interaction between brine/nano-fluid and clay is not the main cause of permeability andporosity impairment in this study.

3.

The retention of nanoparticles during single-phase floodingwater-wet Berea sandstone core plugs has been observed fromdifferential pressure log-jamming and microscopic visualiza-tion under SEM. The retention of nanoparticles inside core pluginduced porosity and permeability impairment.

4.

Even though interfacial tension and contact angle decrease asnanofluid concentration increases, there is no guarantee thatadditional oil recovery is obtained in low–medium permeabil-ity water-wet Berea ss. Higher concentration (e.g. 0.1 wt% ormore) has a tendency to block pore network and will not giveadditional oil recovery in low-permeability reservoir.

5.

A LHP silica nanoparticles suspension seems potentially inter-esting for EOR in water-wet sandstone at certain nanofluidconcentration. Based on this particular study, the silica nano-fluids 0.05 wt% are the best in terms of oil recovery amongother concentrations both for low–medium and high-permeability water-wet Berea ss.

Further studies should be started to evaluate the optimumnanofluid concentration and to investigate the behavior of nano-fluid with surfactants at various wetting conditions.

SI metric conversion factors

mD � 9.869233 E�04¼mm2

inch � 2.540000 E+00¼cmcP � 1.000000 E+00¼mPa sdyn/cm � 1.000000 E+00¼mN/mbar � 1.000000 E�02¼kPambar � 1.000000 E+01¼kPa

Acknowledgments

The authors would like to thank Dr. Suwarno, Bjørnar Engesetand PhD Candidate, Gema Sakti Raspati who have assisted duringthis experiment. We appreciate the assistance from laboratoryengineer staff, Roger Overå, who has prepared Berea ss core plugs.

References

Abbasi, S., Shahrabadi, A., Golghanddashti, H., 2011. Experimental Investigation of ClayMinerals Effects on the Permeability. Paper SPE 144248-MS Presented at SPEEuropean Formation Damage Conference, Noordwijk, The Netherlands, 7–10 June.

Buckley, J., Fan, T., 2005. Crude Oil/Brine Interfacial Tensions. Paper SCA-2005Presented at the International Symposium of the Society of Core Analyst,Toronto, Canada, 21–25 August.

Chengara, A., Nikolov, A., Wasan, D.T., Trokhymchuck, A., Henderson, D., 2004.Spreading of nanofluids driven by the structural disjoining pressure gradient.J. Colloid Interface Sci. 280, 192–201.

Cooke, C.E., Williams, R.D.J., Kolodzie, P.A., 1974. Use of Centrifugal Measurementsof Wettability to Predict Oil Recovery. US Department of the Interior, Report ofInvestigations 7873.

Crocker, M.W., Donaldson, E.C., Marchin, L.M., 1983. Comparison and Analysis ofReservoir Rocks and Related Clays. Paper SPE 11973-MS Presented at the SPEAnnual Technical Conference and Exhibition, San Francisco, CA, 5–8 October.

Das, S.K., Choi, S.U.S., Yu, W., Pradeep, T., 2008. Nanofluids Science and Technology.John Wiley & Sons, Inc Publishing, Hoboken, NJ, ISBN: 0470074736.

Fletcher, A., 2012. Improved Waterflooding and EOR for Lower Permeability Fields.Paper SPE 157158-MS Presented at SPE Asia Pacific Oil and Gas Conference andExhibition (APOGCE), Perth, Australia, 22–24 October.

Grim, R.E., 1953. Clay Mineralogy. McGraw-Hill, New York.Hendraningrat, L., Engeset, B., Suwarno, S., Torsæter, O., 2012. Improved Oil

Recovery by Nanofluids Flooding: An Experimental Study. Paper SPE 163335-MS Presented at SPE Kuwait International Petroleum Conference and Exhibi-tion, Kuwait City, Kuwait, 10–12 December.

Lake, L.W., 1989. Enhanced Oil Recovery. Prentice-Hall, Englewood Cliffs, NJ.Mc.Elfresh, P., Holcomb, D., Ector, D., 2012. Application of Nanofluid Technology to

Improve Recovery in Oil and Gas Wells. Paper SPE 154827-MS Presented at SPEInternational Oilfield Technology Conference, Noordwijk, The Netherlands,12–14 June.

Morrow, N.R., 1985. A review of the effects of initial saturation, pore structure, andwettability on oil recovery by waterflooding. In: Proceeding of the North Sea Oiland Gas Reservoirs Seminar. Graham and Trotman, Ltd., Trondheim, Norway,2–4 December, pp. 179–191.

Morrow, N.R., 1990. Wettability and its effect on oil recovery. J. Pet. Tech. 42 (12),1476–1484. (SPE-21621-PA).

Owens, W.W., Archer, D.L., 1971. The effect of rock wettability on oil–water relativepermeability relationships. J. Pet. Tech. 23 (7), 873–878.

Than, P., Preziosi, D., Joseph, D., Arney, M., 1988. Measurement of interfacial tensionbetween immiscible liquids with the spinning rod tensiometer. J. ColloidInterface Sci. 124 (2), 552–559.

Torsæter, O., Abtahi, M. 2003. Experimental Reservoir Engineering LaboratoryWorkbook. Department of Petroleum Engineering and Applied Geophysics,Norwegian University of Science and Technology (NTNU), Trondheim, Norway.

Treiber, L.E., Duane, L.E., Archer, L., Owens, W.W., 1971. A laboratory evaluation ofthe wettability of fifty oil-producing reservoirs. SPE J. 12, 531–540.

Wasan, D.T., Nikolov, A., 2003. Spreading of nanofluids on solids. J. Nat. 423, 156–159.Wasan, D.T., Nikolov, A., Kondiparty, K., 2011. The wetting and spreading of

nanofluids on solids: role of the structural disjoining pressure. Curr. Opin.Colloid Interface Sci. 16, 344–349.