A Coreflood Investigation of Nanofluid Enhanced Oil Recovery in Low ...

SPE 164106 A Coreflood Investigation of Nanofluid Enhanced Oil Recovery in LowMedium Permeability Berea Sandstone Luky Hendraningrat, SPE, Shidong Li, SPE, and Ole Torsæter, SPE, Norwegian University of Science and Technology/NTNU

Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE International Symposium on Oilfield Chemistry held in The Woodlands, Texas, USA, 8–10 April 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract Nanoparticles have become an attractive agent for improved and enhanced oil recovery (IOR & EOR) at laboratory scale recently. Most researchers have observed promising result and increased ultimate oil recovery by injecting nanofluids in laboratory experiments. In previous study, we observed that interfacial tensions (IFT) decreased when hydrophilic nanoparticles were introduced to brine. The IFT decreases as nanofluids concentration increase and this indicates a potential for EOR. We have also investigated nanofluid flow in glass micromodel and high permeability Berea sandstone (ss) cores, and we observed that the higher concentration of nanofluids; the more impairment of porosity and permeability. Since low permeability oil reservoirs have still huge volume of oil reserves, this study aims to reveal nanofluids possibility for EOR in low-medium permeability reservoir rocks and investigate its suitable concentration. In this paper, laboratory coreflood experiments were performed in water-wet Berea ss core plugs with permeability in range 935 mD using different concentrations of nanofluids. Three nanofluids concentrations were synthesized with synthetic brine; 0.01, 0.05 and 0.1 wt.%. To investigate disjoining pressure as displacement mechanism due to nanoparticles, contact angle between crude oil from a field in the North Sea and brine/nanofluids have been measured. Increasing hydrophilic nanoparticles will decrease contact angle of aqueous phase and increase water-wetness. Despite increasing nanofluid concentration shows decreasing 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 possible application of nanofluid EOR in lower-medium permeability oil reservoir. Introduction Most oil fields around the world have reached or will reach soon the phase where the production rate is nearing the decline period. Hence, the current main challenge is how to delay the abandonment by extracting more oil economically. The latest worldwide industries innovation trends are miniaturization and nanotechnology materials. Nanotechnology is defined as the construction of functional materials, devices, and systems by controlling matter at the nanoscale level (one-billionth meter), and the exploitation of their novel properties and phenomena that emerge at that scale (Das et al., 2008). A nanoparticle, as a part of nanotechnology, has size typically less than 100 nm. It is composed of two entities: the core and a thin shell (Das et al., 2008). The core and shell may have underlying structures and may be composed of more than one entity. The molecular shell has three separate regions; tail group, hydrocarbon chain and active head group, although one or more of these may be absent in a specific case (see Fig. 1). A hydrocarbon chain may be long, as in a polymer, or completely absent, as in an ion protecting the nanoparticle (Das et al., 2008). The shell may also be an extended solid, such as silicon dioxide (SiO2) that we used in this study. The chemical nature of shell will determine solubility of nanoparticles such as lipophobic and hydrophilic nanoparticles (LHP) dissolved in polar solvent such as water; and hydrophobic and lipophilic nanoparticle (HLP) dissolved in non-polar solvents such as toluene. Nanofluids are defined as nanoparticle that has average size less than 100 nm, suspended in traditional heat transfer fluid such as water, oil or ethylene glycol (Das et al., 2008). Nanofluid technology, as a part of nanotechnology, is a new interdisciplinary area of great importance where nanoscience, nanotechnology, and thermal engineering come across. It has developed largely over the past decade and revealed its potential applications in oil and gas industries. Our main research aims are to investigate the possibility of nanofluids as future or alternative improved/enhanced oil recovery method.

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Displacement Mechanism Oil recovery mechanism using nanoparticles suspension has been experimentally investigated by Wasan and Nikolov (2003); Chengara et al. (2004); and Wasan et al. (2011) and called disjoining pressure mechanism. Later, Mc.Elfresh et al. (2012) described the energies that drive this mechanism are Brownian motion and electrostatic repulsion between the nanoparticles. The electrostatic repulsion force between those particles will be bigger when nanoparticle size is smaller. When amount of the nanoparticles are increasing, the force will increase. Presence of these nanoparticles in three-phase contact region has a tendency to create a wedge-film structure. Structural disjoining pressure is correlated to the fluids ability to spread along the surface of a substrate due to imbalance of the interfacial forces 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 1o and the result is a wedge film. This wedge film will act to separate formation fluid such as oil, paraffin, water and gas from formation surface (Mc.Elfresh et al., 2012). Driven by the aqueous pressure of the bulk liquid, the nanofluid is 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 for the spreading of the nanofluids is the structural disjoining pressure (film tension) gradient (Δγ) directed towards the wedge from the bulk solution. The film tension is high near the vertex because of the nanoparticle structuring in the wedge confinement. It drives the nanofluids to spread at the wedge tip as the film tension increases towards the vertex of the wedge. They also investigated that spreading coefficient increases exponentially with a decrease in the film thickness or decrease in the number of particle layers inside the film. As the film thickness decreases towards the wedge vertex, the structural disjoining pressure increases.

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 as aqueous phase due to nanoparticles structuring in the wedge-film (from Wasan et al., 2011)

In our preliminary two-phase flow EOR study using transparent glass micromodel (porosity 44% and permeability 25 D) showed that nanofluids 0.1wt.% could reduce residual oil saturation as shown in Figure-2. However this porous medium has very high porosity and permeability and does not represent common oil reservoir rocks. Previous coreflood experiment using water-wet Berea ss with average porosity 23% and permeability 375 mD showed that nanofluids with very low concentration 0.01 wt.% could enhance oil recovery almost 2% points (Hendraningrat et al., 2012). Hence the goal in this study is to reveal the possibility of using nanofluids as EOR method in low-medium permeability rocks and investigate its suitable nanofluids concentration.

b)

a)

0.4-0.5 mm

Brine

Nanofluid Oil Oil

Flow direction

Flow direction

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

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Experiments Material A LHP with single particle size 7 nm, dominantly most distributed in range 21-40 nm and consists more than 99.8% of silicon dioxide (SiO2), has been used in this study. Other minor elements are aluminum oxide (Al2O3) ≤ 0.05 %, titanium dioxide (TiO2) ≤ 0.03%, hydrogen chloride (HCl) ≤ 0.025% and ferric oxide (Fe2O3) ≤ 0.003%. It has acidity with pH range from 3 to 5. The specific surface area of LHP is 300 m2/g. The LHP has been characterized under Zeiss Supra 55 VP low vacuum Scanning Electron Microscope (SEM) with scale of 200 nm and nanoparticle distribution dispersed in brine through Nanosight measurement as shown in Figure-3.

Fig. 3─ Nanoparticles characterization under SEM (magnification >50k times) with nanoparticles distribution analysis using Nanosight (Based on Dynamic Light Scattering method)

In this study, a degassed crude oil from a field in North Sea has been used. It has density and viscosity of 0.826 g/cm3 and 5.10 mPas, respectively. Synthetic reservoir brine was made as base fluid solution between sodium chloride (NaCl) 3.0 wt.% and deionized water. The density of brine was 1.02 g/cm3, viscosity 1.0 mPas and pH 6.76 at 21.4oC. The density and viscosity were measured using pycnometer and Brookfield viscometer respectively. This brine was also used as dispersed fluid for these nanoparticles. The reason, brine is present in oil reservoirs and easily available in offshore fields. The most important LHP nanoparticles can easily be dispersed in water-based fluid such as brine. Nanofluids with various weight concentration 0.01, 0.05 and 0.1 wt.% were synthesized using high speed magnetic stirring for 3-4 minutes and continued with sonicator at 40-100% amplitude for 3-5 minutes. Table 1 shows fluid properties measurement of brine and various nanofluid concentrations at ambient condition. Table 1. Fluid properties

Fluid Brine, NaCl 3 wt.% Nanofluid 0.01 wt.% Nanofluid 0.05 wt.% Nanofluid 0.1 wt.% Crude Oil

Density, g/cm3 1.022 1.012 1.015 1.017 0.826

Viscosity, mPa.s 1.001 1.006 1.010 1.015 5.10

pH 6.76 6.26 6.16 5.25 -

Temperature, oC 21.4 21.7 21.2 20.0 22.0

Porous medium Several low-medium permeability water-wet Berea ss core plugs with range of permeability from 9 to 35 mD were used in this study. As comparison, several higher permeability (range 150-400 mD) water-wet Berea core plugs were also applied. First, core plugs were cleaned using toluene through soxhlet extraction apparatus at 65-70 oC for 6 hours. Cleaning with methanol through soxhlet extraction at similar condition and duration followed. The core plugs were heated in the oven at 70 oC for 6 hours. The dry weight, length, diameter and porosity were measured. Helium porosimeter and liquid Hassler permeameter were used to measure porosity and permeability respectively. The measured dimension and average petrophysical properties at initial condition are listed in Table 2. Pore size of core plugs has been observed roughly under SEM. Crocker et al. (1983) have investigated that average pore size for Berea ss (porosity 19.2% and permeability 302 mD) is 18 µm . Based on our observation as shown in Fig. 4b, the pore size of low-medium permeability seems at a glance less than 10 µm. Meanwhile, higher permeability pore size shows higher pore size around 25-30 µm from Fig. 4d.

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Table 2. Dimensions and average petrophysical properties at initial condition

Berea ss # L1 L2 L3 L4 L5 L6 H1 H2 H3 H4

Length, mm 40.83 40.73 41.05 40.75 41.04 40.08 48.34 48.09 48.12 48.02

Diameter, mm 37.98 37.96 37.94 37.92 37.84 37.95 37.93 37.92 37.91 37.90

Pore Volume, cm3 7.03 6.42 7.13 6.70 6.88 6.49 12.67 12.41 12.52 12.42

Porosity, % 15.02 13.93 15.37 14.55 14.90 14.10 23.20 20.01 23.04 22.93

Avg. Liq. Permeability, mD 13 9 35 20 18 10 392 156 302 354

*L = Low-permeability; H = High-permeability

Low-medium Berea ss

b)

4.1 cm

a)

3.8 cm

High Permeability Berea ss

Mag = 3000X

EHT = 15. 00 kV

WD = 11.5mm

d)

4.8 cm

c)

20 µm

3.8 cm

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)

Coreflood Setup The experiment aims to reveal nanofluids possibility for EOR in low-medium reservoir permeability rocks and investigate suitable nanofluids concentration. Hence various nanofluids were injected as tertiary recovery mode after brine flooding at room temperature. The injection rate was kept constant at 0.2 cm3/min. Figures 5 and 6 show experimental instruments and schematic of coreflood setup respectively. The pump injected exxol D-60 as pump fluid from bottle through 1/8 inch pipe to push the piston plate located inside the vessel. The piston plate is also useful to separate between different fluids in the similar cylinder without mixing. There are 3 different vessels installed with piston plate in each vessel. Those vessels were filled up each with brine, crude oil and nanofluid. Valves were installed at inlet and outlet of the vessel to regulate fluid flow. There is a bypass flowline to clean the line before injecting another fluid. The influent flowlines from vessels are connected to Hassler core holder. The sleeve pressure was set to 20 bar in the Hassler core holder. Oil flowline at vessel’s outlet are separated from others vessel’s outlet to minimize early mixing of those fluids. The differential pressure was recorded by precision pressure gauge (range 0-3 bar) that connected to the PC monitor. The accumulator tubes were prepared to measure the effluent from core during flooding process.

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Fig. 5─Experimental Instruments

15

17

10 11 4 4 8

7

2

4

4

9 18

6 1

4

3

6

5

6 5

5

13 12

14

16 19

1) Pump fluid (Exxol D60); 2) injection line; 3) Micro Pump; 4) Valve; 5) Pump Fluid in Vessel-A; 6) Piston plate; 7) Brine in Vessel-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) Pressure gauge; 16) Sleeve pressure; 17) connection cable; 18) Computer; 19) Accumulator Fig. 6─Schematic of Experimental Setup

Coreflood Procedure The core plug dimensions and dry weight were obtained. Then the core plugs were fully saturated with brine using vacuum container for app. 1-2 hours at a pressure of 0.1 bar. The coreflood instrument was setup as shown in Fig. 6. The sleeve pressure was set at 20 bar into core cell. The drainage process was started by injecting degassed crude oil with rate from 0.2 to 1.0 cm3/min until surely no more brine produced. To reach this situation required about 3-10 PV injection. The initial water saturation was established. As first imbibition process, brine was injected at constant rate 0.2 cm3/min approx. 3-5 PV until surely no more oil produced and thereby residual oil saturation was established. Then the injection was continued at constant rate 0.2 cm3/min approx. 3-4 PV of nanofluid as tertiary recovery mode. There are three different nanofluids concentrations: 0.01; 0.05 and 0.1 wt.%. The oil recovery performance (% of OOIP) and decreased residual oil saturation were evaluated. Table 3 shows how many PV were injected during drainage, imbibition process using brine flooding and nanofluids EOR scenario.

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Table 3. Saturation process and EOR scenarios


PV Injected at Drainage process 6.1 4.7 7.0 7.5 7.3 10.8 3.9 4.0 4.0 3.2

Initial Water Saturation, % 18.94 15.89 20.06 20.90 31.67 26.03 15.56 24.25 23.29 24.34

Initial Oil Saturation, % 81.06 84.11 79.94 79.10 68.33 73.97 84.44 75.75 76.71 75.66

PV Injected at Imbibition process with Brine 3.4 3.2 3.0 2.7 3.3 5.2 3.7 3.0 3.2 3.1

Oil saturation after Brine Injection, % 35.98 53.74 34.36 34.70 25.81 37.75 41.04 29.01 27.57 37.43

Nanofluids Concentration for EOR Scenario 0.01 wt.% 0.01 wt.% 0.05 wt.% 0.05 wt.% 0.1 wt.% 0.1 wt.% 0.01 wt.% 0.05 wt.% 0.05 wt.% 0.1 wt.%


Interfacial Tension Measurement The interfacial tension (IFT) between degassed crude oil and brine/nanofluids as aqueous phase was measured by using SVT20 spinning drop video tensiometer around 1 hour at ambient condition. The drop volume was in range 2-3 µL. The rotation speed was kept around 5000-6000 rpm. The formula to measure IFT is as follows (Than et al., 1986):



.

.

where  is interfacial tension (dyn/cm), Δρ is density difference (g/cm3), is rotational rate of the cylinder (s-1), Dapp is the measured drop diameter (cm), n is the refractive index of the heavy fluid, D is the true diameter of the drop (D = ), JD is correction factor and function of L/D; and L/D is the aspect ratio (e.g. the ratio of the drop length to its diameter).

ρ1 R=

ρ2

L

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

As input data, refractive index was measured using refractometer Mettler Toledo for all aqueous phase and summarized in Table 4. The refractive index slightly increases with nanofluids concentration increase. Table 4. Refractive Index for Aqueous Phase

Fluid Deionized Water Brine, NaCl 3 wt.% Nanofluid 0.01 wt.% Nanofluid 0.05 wt.% Nanofluid 0.1 wt.%

Average n 1.33100 1.33624 1.33612 1.33646 1.33662

Temperature, oC 20.1 19.9 20.2 20.8 20.5

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Contact Angle Measurement Contact angle, θ, is a quantitative measurement of the wetting characteristic of a solid by a liquid and defined geometrically as the angle formed by a liquid at the three-phase boundary where a liquid, gas (lighter) and solid intersect. Low value of θ indicates that the liquid spreads or wets. Otherwise high value indicates poor wetting. Treiber et al. (1971) defined contact angle in 3-phase system (water, oil and rock surface) as follows: water-wet in range from 0o to 75o, intermediate/neutral-wet in range 75o-105o and oil-wet in range 105o-180o. A zero contact angle represents that the denser fluid is completely wetting the solid. In this experiment, contact angle was measured directly on polished synthetic silica using Goniometry KSV CAM instrument at room condition. The system consists of crude oil; brine/nanofluids and polished synthetic silica (see Fig. 8). The measurement is based on Young formula as follow: .

where σ describes interfacial tension components of phase, indices s and l stand for solid and liquid phases, σsl represents the interfacial tension between the two phases and θ is contact angle corresponding to the angle between vectors σl and σsl.

Aqueous phase (brine/nanofluids) ρ1

σl

Oil drop ρ2

σs

θ

σsl

Substrate (Silica/Quartz)

Fig. 8─Contact angle formation on polished synthetic silica between crude oil and Brine/nanofluids according to Young formula

Results and Discussion Effect of LHP silica nanofluids on IFT and contact angle In this study, parameters involved in the disjoining pressure mechanism, such as lowering IFT and altering wettability are studied. An assessment of the relationship between interfacial tension, wettability and oil recovery in low-medium permeability water-wet Berea ss due to presence of LHP silica nanoparticles are performed. Introducing silica LHP nanoparticles into the brine-oil system was observed to give lower IFT and the decreased might be large enough to produce more oil. Buckley and Fan (2005) reported IFT impacts on capillary pressure, capillary number, adhesion tension, and the dimensionless time for imbibition. The capillary number increased with decrease of IFT and consequently some residual oil is mobilized. Figure 9 shows IFT measurement of crude oil against brine /nanofluids at various concentrations. IFT of brine-crude oil system is 19.2 mN/m and is considered as reference value. A LHP silica nanoparticle has ability to decrease IFT at the oilbrine interface and the value was about half of the reference value at concentration of 0.01 wt.%. The interfacial tension is sensitive to nanofluids concentration. As we can see, IFT decreases as nanofluids concentration increase. We are unsure with the result when measuring at higher nanofluids concentrations than 0.05 wt.%. However pH of LHP silica nanofluids will decrease with increased concentrations of nanoparticles (see Table 1). The pH significantly decreased from around 6 to 5 when nanofluid concentration increased from 0.05 to 0.1 wt.%. The effect of aqueous phase’s pH in IFT oil-water system has been investigated by Buckley and Fan (2005). They reported below pH of 6, the trend showed IFT would likely decrease for pH reduction from 6 to 3. Hence, it is expected that the IFT for 0.1 wt. % will follow the decline trend.

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Fig. 9─Interfacial tension and contact angle measurement for crude oil against brine with various nanofluids concentrations at ambient condition

Owens and Archer (1971) reported that increasing the water-wetness increases ultimate oil recovery. Morrow (1990) observed also that oil recovery decreased with decreasing water wetness. These results are consistent with the intuitive notion that strong wetting preference of the rock for water and associated strong capillary imbibition forces give the most efficient oil displacement (Morrow, 1990). However Cooke et al. (1974) reported that increasing oil-wetness increases oil recovery. Morrow (1985) also observed that oil recovery was maximum for cores at intermediate wettability, which is probably related to disconnection and trapping of oil phase. Hence wettability has a vital role in crude oil production (Morrow, 1990) and determines the recovery efficiency of displacement processes. Wettability affects both the distribution of hydrocarbon and aqueous phases within the rock matrix and dynamics of displacement processes (Fletcher, 2012). Contact angle is the most universal measurement of the surfaces wettability and an approach to measure reservoir wettability (Morrow, 1990). Figures 9-10 show contact angle measurements of crude oil against brine /nanofluids at various concentrations on polished synthetic silica. Nanoparticles lower the contact angle of aqueous phase and consequently result in small hysteresis. The trend showed that increased hydrophilic silica nanofluid concentration will increase water wetness. The electrostatic repulsion force between the particles will be bigger when amount of nanoparticle is huge. Driven by the aqueous pressure of the bulk liquid, the nanofluid will spread along the solid surface and decrease contact angle.

Fig. 10─Contact angle measurement (flipped image) for crude oil against brine with various nanofluids concentrations at ambient condition

Differential pressure profile during coreflood experiment The differential pressure was recorded by precision pressure gauge Keller PD-33X with range 0-3 bar. Unfortunately, differential pressure was stopped recording for all low-medium permeability core plugs when it reached almost the maximum limit after around 0.5 PV. Figure 11 shows the differential pressure for core plug L2 that has porosity 14% and permeability 9 mD. It was injected 3PV with brine until no more oil was produced and continued with nanofluid 0.01 wt.% as tertiary mode at constant rate 0.2 cm3/min.

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Pressure recording was stopped due to max. gauge limit

Brine flooding

Nanofluids flooding

Fig. 11─ Oil Recovery Performance, Differential Pressure vs. Injected PV of Core L2: Imbibition and EOR process with Nanofluids 0.01 wt.% at constant injection rate 0.2 cm3/min.

Figure 12 shows the differential pressure for core plugs H2. Unlike L2, the pressure for H2 was completely recorded during flooding process. It has porosity 20% and permeability 156 mD. It was injected 3PV with brine until no more oil produced and continued with nanofluid 0.05 wt.% as tertiary mode at constant rate 0.2 cm3/min. In the first 0.5 PV brine flooding, 2-phase flow existed and increased differential pressure was observed. Once brine 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 the injection was stopped at 3 PV. About 3 PV of nanofluid injection in core plug H2. The differential pressure increased when nanofluid was injected to this core plug. The reason may be that some nanoparticles adsorbed and blocked pore throats and thereby altered rock and fluid properties including wettability and interfacial tension. Nanofluid flooding needs around 1 PV to enhance oil recovery. The final increase in oil recovery for core plug H2 is about 5-6% points.

Brine Breakthrough

Pressure recording was stopped

Brine flooding

Nanofluids flooding

Fig. 12─ Oil Recovery Performance, Differential Pressure vs. Injected PV of Core H2: Imbibition and EOR process with Nanofluids 0.05 wt.%.

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Effect of LHP silica nanofluids on oil recovery Effects of introducing LHP silica nanofluids that altered wettability and interfacial tension on oil recovery have been investigated through laboratory coreflood displacement test on several core plugs with low-medium and high permeability and plotted in Figs. 13-14. All results have been tabulated in Table 5. The oil recovery after brine injection is in the range 36-62 % of OOIP for low-medium permeability and the trend is increasing oil recovery with increase rock permeability. Meanwhile higher permeability core plugs has 50-64% recovery of OOIP after brine flooding. Nanofluids were injected around 3 PV at constant injection rate 0.2 cm3/min and around 0.5-1 PV was needed to start displacing more oil. Displacement efficiency due to nanofluids has been evaluated and summarized in Table 5. The displacement efficiency of nanofluids calculated here follows the formula below: where Sor1 represents residual oil saturation after brine injection and Sor2 represents residual oil saturation after nanofluids for EOR. We observed that displacement efficiency is higher when nanofluids concentration is increased from 0.01 to 0.05 wt.% both in low-medium permeability and high permeability core plugs. The residual oil saturation decreases when nanofluid concentration is increased for low-permeability core plugs (Figs. 15-17). The reduction of residual oil saturation was less than 5% points. Consequently, the ultimate oil recovery increases as the nanofluids concentration increases from 0.01 to 0.05 wt.% but the recovery is less than 70% oil recovery. Compared to low-medium permeability, additional oil recovery due to nanofluids is higher in high permeability core plugs at given nanofluids concentration. There was no additional oil recovery in low-medium permeability reservoir and less oil recovery in high permeability rocks when nanofluids concentrations increased to 0.1 wt.%. Based on previous observation (Hendraningrat, 2013), this was caused by particles blocking the pore network rather than displacing more oil. Overall, the nanofluids concentration at 0.05 wt.% is the best among other concentrations in this study on oil recovery both for low-medium and high permeability water-wet Berea ss core plugs. In addition its displacement efficiency is also the highest for all type of permeability of the core plugs. In further, optimum nanofluids concentration will be studied to get maximum oil recovery from nanofluids EOR.

Lower k

Fig. 13─ Oil Recovery Performance vs. Injected PV for low-medium permeability core plugs with various nanofluids concentrations.

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Fig. 14─ Oil Recovery Performance vs. Injected PV for high permeability core plugs with various nanofluids concentrations.

Table 5. Oil Recovery due to Brine and EOR with nanofluids at various concentrations and Displacement Efficiency at constant injection rate 0.2 cm3/min


Oil saturation after Brine Injection (Sor1), % 35.98 53.74 34.36 34.70 25.81 37.75 41.04 29.01 27.57 37.43

Oil Recovery after Brine Injection, % OOIP 55.61 36.11 57.02 56.13 62.23 48.96 51.40 61.70 64.06 50.53

Nanofluids Injection for EOR Scenario 0.01 wt.% 0.01 wt.% 0.05 wt.% 0.05 wt.% 0.1 wt.% 0.1 wt.% 0.01 wt.% 0.05 wt.% 0.05 wt.% 0.1 wt.%

PV Injected at EOR process with Nanofluids 2.7 3.1 3.0 3.4 2.8 3.0 2.8 3.1 3.1 3.5

Oil saturation after Nanofluids Injection (Sor2), % 33.84 52.18 29.45 32.31 25.81 37.75 37.09 24.98 23.97 34.21

Ultimate Oil Recovery after Nanofluids, % OOIP 58.25 37.96 63.16 59.15 62.23 48.96 56.07 67.02 68.75 54.79

Displacement Efficiency of Nanofluids, ED % 5.93 2.90 14.29 6.88 0.00 0.00 9.62 13.89 13.04 8.60


Further works are necessary to establish the connection between these results and relative permeability curves. It is also necessary perform experiments on core plugs with different wettabilities (neutral-wet and oil-wet). In addition, silica nanoparticles associated with appropriate surfactant is a possible next research step. Hopefully, surfactants will give smaller interfacial tension and remove fluid such as oil, paraffin and polymer residues and thereby make the substrate water-wet as mentioned by Mc.Elfresh et al. (2012).

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Fig. 15─ Reducing Residual oil saturation with nanofluids 0.01 wt.% . Both low-medium and high permeability core plugs decrease residual oil saturation.

Fig. 16─ Reducing Residual oil saturation with nanofluids 0.05 wt.% . Both low-medium and high permeability core plugs decrease residual oil saturation.

Fig. 17─ Reducing Residual oil saturation with nanofluids 0.1 wt.% . Only in the high permeability core plug decreases residual oil saturation.

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Concluding remarks 1.

Even though interfacial tension and contact angle decrease as nanofluids concentration increase, there is no guarantee that additional oil recovery is obtained in low-medium permeability water-wet Berea ss. Higher concentration (e.g. 0.1 wt.% or more) has a tendency to block pore network and will not give additional oil recovery in low permeability reservoir. 2. A LHP silica nanoparticles suspension seems potentially interesting for EOR in water-wet low-medium permeability sandstone at certain nanofluids concentration. Based on this particular study, the silica nanofluids 0.05 wt.% is the best in terms of oil recovery among other concentrations both for low-medium and high permeability water-wet Berea ss. Further studies should be started to evaluate optimum nanofluid concentration and to investigate the behavior of nanofluid with surfactants at various wetting conditions. Acknowledgments The authors gratefully acknowledge to laboratory engineer staff, Roger Overå, who has prepared Berea ss core plugs and PhD Candidate, Gema Sakti Raspati, who has assisted in refractive index measurement. References Das, S.K., Choi, S.U.S., Yu, W., and Pradeep, T. 2008. Nanofluids Science and Technology. Hoboken, New Jersey: John Wiley & Sons, Inc Publishing. ISBN 0470074736. Wasan, D.T., and Nikolov, A. 2003. Spreading of Nanofluids on Solids. Journal of Nature (423): 156-159. Chengara, A., Nikolov, A. Wasan, D.T., Trokhymchuck, A., and Henderson, D. 2004. Spreading of Nanofluids Driven by the Structural Disjoining Pressure Gradient. Journal of Colloid and Interface Science (280): 192–201. Wasan, D.T., Nikolov, A., and Kondiparty, K. 2011. The Wetting and Spreading of Nanofluids on Solids: Role of the Structural Disjoining Pressure. Current Opinion in Colloid & Interface Science (16): 344-349. Mc.Elfresh, P., Holcomb, D., and Ector, D. 2012. Application of Nanofluid Technology to Improve Recovery in Oil and Gas Wells. Paper SPE 154827-MS presented at SPE International Oilfield Technology Conference, Noordwijk, The Netherlands, 12-14 June. http://dx.doi.org/10.2118/154827-MS Hendraningrat, L., Engeset, B., Suwarno, S., and Torsæter, O. 2012. Improved Oil Recovery by Nanofluids Flooding: An Experimental Study. Paper SPE 163335-MS presented at SPE Kuwait International Petroleum Conference and Exhibition, Kuwait City, Kuwait, 10-12 December. http://dx.doi.org/10.2118/163335-MS Crocker, M.W., Donaldson, E. C., and Marchin, L.M. 1983. Comparison and Analysis of Reservoir Rocks and Related Clays. Paper SPE 11973-MS presented at the SPE Annual Technical Conference and Exhibition, San Francisco, California, 5-8 October. http://dx.doi.org/10.2118/11973-MS Than, P., Preziosi, D., Joseph, D., and Arney, M. 1988. Measurement of Interfacial Tension between Immiscible Liquids with the Spinning Rod Tensiometer. Journal of Colloid and Interface Science 124 (2): 552–559. Treiber, L.E., Duane, L.E., Archer, L., and Owens, W.W. 1971. A Laboratory Evaluation of the Wettability of Fifty OilProducing Reservoirs. SPE Journal (12): 531-540. Buckley, J., and Fan, T. 2005. Crude Oil/Brine Interfacial Tensions. Paper SCA-2005 presented at the International Symposium of the Society of Core Analyst, Toronto, Canada, 21-25 August. Owens, W.W., and Archer, D.L. 1971. The Effect of Rock Wettability on Oil-Water Relative Permeability Relationships. J. Pet Tech, July: 873-878. Morrow, N.R. 1990. Wettability and Its Effect on Oil Recovery. J. Pet Tech 42 (12): 1476-1484. SPE-21621-PA. http://dx.doi.org/10.2118/21621-PA Cooke, C.E., Williams, R.D.J., and Kolodzie, P.A. 1974. Use of Centrifugal Measurements of Wettability to Predict Oil Recovery. U.S Department of the Interior, Report of Investigations 7873. Morrow, N.R. 1985. A Review of the Effects of Initial Saturation, Pore Structure, and Wettability on Oil Recovery by Waterflooding. Proceeding of the North Sea Oil and Gas Reservoirs Seminar. Graham and Trotman, Ltd: 179-191. Trondheim, Norway, 2-4 December. Fletcher, A. 2012. Improved Waterflooding and EOR for Lower Permeability Fields. Paper SPE 157158-MS presented at SPE Asia Pacific Oil and Gas Conference and Exhibition (APOGCE), Perth, Australia, 22-24 October. http://dx.doi.org/10.2118/157158-MS Hendraningrat, L., Engeset, B., Suwarno, S., and Torsæter, O. 2013. Laboratory Investigation of Permeability and Porosity Impairments in Berea Sandstones due to Hydrophilic Nanoparticles Retention. Paper W0182 presented at International Conference on Geotechnical Engineering, Hammamet, Tunisia, 21–23 February.

14

SPE 164106

SI Metric Conversion Factors mD inch cP dyn/cm bar mbar

x x x x x x

9.869233 2.540000 1.000000 1.000000 1.000000 1.000000

E-04 E+00 E+00 E+00 E-02 E+01

= = = = = =

µm2 cm mPa.s mN/m kPa kPa