210 April 2012 SPE Reservoir Evaluation & Engineering

Residual-Oil Recovery Through Injection of Biosurfactant, Chemical Surfactant, and Mixtures of Both Under Reservoir

Temperatures: Induced-Wettability and Interfacial-Tension Effects

H. Al-Sulaimani, SPE, Y. Al-Wahaibi, SPE, S. Al-Bahry, A. Elshafi e, A. Al-Bemani, SPE, and S. Joshi, Sultan Qaboos University; and S. Ayatollahi, SPE, Shiraz University

SummaryIn this study, a biosurfactant produced by a Bacillus subtilis strain isolated from oil-contaminated soil from an Omani oil field was tested for its potential in enhancing oil recovery by a series of coreflooding experiments. It was found that the performance of the biosurfactant was increased by mixing with chemical surfactants, by which the maximum production went up to 50% of residual oil at a mixing ratio of (50:50). The second objective of this study was to investigate the effects of the biosurfactant on wettability alteration and to estimate its tendency to loss caused by adsorp-tion. The influence of biosurfactant on wettability was studied by contact-angle measurements, atomic force microscopy (AFM) technique on few-layer graphene (FLG) surfaces, and Amott wetta-bility tests on Berea sandstone cores. Contact-angle measurements showed that the wettability of the biosurfactant solution changes to more oil-wet as the angle decreased from 70.6 to 25.32° when treated with 0.25% (w/v) biosurfactant solution. Amott testing showed a change in wettability index from strongly water-wet in the untreated core toward less water-wet in biosurfactant-treated cores. These results confirmed the ability of the biosurfactant to alter the wetting conditions against different surfaces, thereby serv-ing as a mechanism for enhancing oil recovery. The maximum loss of biosurfactant caused by adsorption was 1.2 mg/g of rock, which is comparable with reported chemical-surfactant values.

IntroductionBiosurfactants have received wide attention recently because of their surface effects and variable applications in industrial processes. In the oil industry, biosurfactants are used for enhanced oil recovery, biore-mediation, dispersion, and transfer of crude oils (Lee et al. 2007).

There are many B. subtilis strains that were reported to produce a surface-active material called surfactin. The biosurfactant used in this study was produced by a B. subtilis strain W19 isolated from oil-contaminated soil samples from an Omani oil field (Al-Sulai-mani et al. 2010). This strain was found to produce biosurfactant at a yield of 2.5 g/L, critical micelle concentration (CMC) of 0.4 g/L; and the biosurfactant reduced the interfacial tension (IFT) against n-heptane from 46.6 to 3.28 mN/m.

Al-Sulaimani et al. (2011) also reported that the biosurfactant had a potential for microbial-enhanced-oil-recovery (MEOR) tech-nology because it yielded a total production of 23% of residual oil. In this study, the possibility of enhancing the performance of the biosurfactant for oil recovery by mixing with commercially available chemical surfactants was investigated. Previous studies reported that biosurfactants could potentially be used in con-junction with synthetic surfactants to provide more-cost-effective enhanced oil recovery and subsurface remediation (Daoshan et al. 2004). The economic efficiency of biosurfactants depends on the

use of low-cost raw materials, such as molasses or cheese whey, which account for 10–30% of the overall cost (Cameotra and Makkar 2002). Portwood (1995) reviewed hundreds of projects and concluded that the cost of the MEOR process, including biosurfac-tants, ranges from USD 0.25 to 0.50 per barrel of oil produced and does not go up as oil production increases. A more recent study reported that the price of biosurfactants ranges between USD 2 and 3 per kg (Hazra et al. 2011). It was reported that the reduction in IFT by the surfactants has to be ultralow (whereas the IFT values should be in the range of 10−3 mN/m) to enhance oil recovery through increasing the capillary number (Aoudia et al. 2006; Cur-belo et al. 2007; Zhu et al. 2009; Iglauer et al. 2010). Although the minimum IFT value obtained by the biosurfactant is not ultralow, other recovery mechanisms are expected to take place.

Recently, wettability alteration has been proposed as one of the mechanisms of MEOR; several studies reported the relation-ship between IFT reduction and alteration of wetting conditions following microbial treatment (Sayyouh and Al-Blehed 1995; Mu et al. 2002; Zekri et al. 2003; Kowalewski et al. 2006; Zargari et al. 2010). In this study, wettability alteration by the biosurfactant produced by B. subtilis Strain W19 is investigated by contact-angle measurements, AFM analyses on graphene surfaces, and Amott tests. Zargari et al. (2010) used AFM to investigate the surface change on mica plaques caused by three bacterial-treatment meth-ods and found that all three conditioning solutions were capable of altering the wettability of mica.

Amott tests were conducted on Berea sandstone cores by esti-mating the wettability index (WI), which is a number between –1 and 1 describing the affinity of the rock to certain fluids. A rock is water-wet when WI is between 0.3 and 1. It is weakly water-wet when the WI is between 0 and 0.3, while it is described as oil-wet when WI is less than 0 (Anderson 1986; Salehi et al. 2006).

This study includes adsorption analysis to quantify the amount of biosurfactant adsorbed (in milligrams) per unit gram of solid or crushed rocks. This is done to assess the applicability of using this biosurfactant for enhancing oil recovery, and of comparing it with the commercially available chemical surfactants.

Materials and MethodsBiosurfactant Production and Extraction. The procedure for bacterial growth and biosurfactant production is described in previous studies (Al-Sulaimani et al. 2010, 2011). Briefl y, the B. subtilis Strain W19 was grown in a minimal media (Table 1) con-taining 2% (w/v) glucose and incubated for 16 hours at 40�C and 160 rev/min. The bacterial cells were separated from the broth by centrifuging at 10,000 rev/min for 20 minutes at 20�C in a high-speed centrifuge (Beckman, USA, JLA 16.250 rotor).

For biosurfactant extraction, the cell-free broth was concentrated by the acid-precipitation method (Youssef et al. 2007). The precipi-tated biosurfactant was collected by centrifuging at 10,000 rev/min, and finally the biosurfactant powder was obtained by spraydrying at 160�C using a minispraydryer (Buchi, Switzerland).

Copyright © 2012 Society of Petroleum Engineers

Original SPE manuscript received for review 27 June 2011. Revised manuscript received for review 4 October 2011. Paper (SPE 158022) peer approved 21 December 2011.

April 2012 SPE Reservoir Evaluation & Engineering 211

Rock and Fluid Samples. Identical Berea core plugs were used for the corefl ooding tests and Amott tests for wettability-alteration stud-ies, with an average porosity and permeability of 13% and 200 md, respectively. The core plugs are 3 in. long, with a diameter of 1.5 in. AFM analysis and Amott tests were conducted using biosurfactant dissolved in formation water or distilled water. The composition of the formation water is listed in Table 2. Furthermore, original crude oil from an Omani fi eld is used to saturate the core samples. The characteristics of the crude oil are given in Table 3. Chemical surfactants used in this work are ethoxylated sulfonates, S-8B.

Corefl ooding Experiments. The procedure for core cleaning, prep-aration, and initial water saturation was performed as described in previous studies (Al-Sulaimani et al. 2010, 2011). The cores were then fl ooded with oil at 6 cm3/h until no more water was produced. The oil initially in place was indicated by the volume of water displaced. After that, the cores were subjected to waterfl ooding at 30 cm3/h until no further oil was produced. The residual oil was then calculated by measuring the amount of oil produced from the waterfl ood. Then, 4 pore volumes of the biosurfactant and chemi-cal-surfactant-mixture solutions was injected at different ratios of 100:0, 25:70, 50:50, 75:25, and 0:100 of biosurfactant to chemical surfactant, respectively, all at a fi nal concentration of 0.25% (w/v). This was performed as a tertiary recovery stage, and extra oil recovery was determined. All corefl oods were conducted at 60�C to mimic the average reservoir temperature of the fi eld of interest.

Wettability-Alteration StudiesContact-Angle Measurements. Contact angles of the untreated samples (distilled water) and samples treated with biosurfactant at a concentration of 0.25% (w/v) were measured using the goni-ometer, Drop Shape Analysis System, DSA100 (Kruss, Germany). The principle behind this instrument has been explained previously (Al-Sulaimani et al. 2011). All measurements were made in trip-licate at ambient temperature (25±2)�C and pressure (1 atm), and the average values were reported.

AFM Analysis. The surface topography change caused by bio-surfactant treatment on FLG samples was investigated by AFM (Veeco-Leica). The samples were prepared on 1-cm-long by 0.5-cm-wide graphene layered mechanically by adhesive tape. The fi rst sample was dipped perpendicularly into an untreated medium (control), which will serve as a reference. The second sample was dipped into 0.25% (w/v) biosurfactant solution dissolved in

distilled water. The samples were scanned with 10-, 5-, and 1-µm scan length at a rate of 0.5 Hz. All samples were run in triplicate.

WI Determination. The WI evaluation tests were conducted on identical Berea core plugs to investigate the effect of biosurfactant on the wettability tendency of the cores. Four tests were conducted; the fi rst was without the biosurfactant treatment, and this was the reference (control) test. The second was performed by soaking the core for 48–72 hours at 40°C in a 0.25% (w/v) solution of biosur-factant dissolved in distilled water. The third test was performed by dissolving the biosurfactant in formation water (Table 2) to investigate the interaction of biosurfactant with original reservoir fl uid and the extent of the rock-wettability change. In the fourth test, the effect of temperature was examined at 60°C to simulate the average reservoir temperatures in Omani fi elds. The general procedure for the WI determination is as follows:

1. The soaked core was flooded with oil to initial oil satura-tion Soi.

2. The core was kept in an Amott cell filled with water or bio-surfactant solution for spontaneous imbibitions, and the amount of oil produced was estimated, which will be the amount of water spontaneously imbibed Vwimb.

3. The core was flooded with water or biosurfactant solution (forced imbibition) to reach residual-oil saturation Sor. The amount of oil forcibly produced was measured (Vwf).

4. The core was then placed in an inverted Amott cell filled with oil for spontaneous imbibition of oil, and the amount of water produced was estimated (Voimb).

5. Finally the core was flooded by oil to reach irreducible water satu-ration and the amount of water forcibly produced was estimated (Vof).

The water-wettability index (WWI), the oil-wettability index (OWI), and the relative wettability index (WI) can then be calcu-lated by Eqs. 1 through 3:

WWIV

V Vw

w w f

=+imb

imb

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1)

OWIV

V Vo

o o f

=+imb

imb . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2)

WI = WWI – OWI. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3)

Adsorption StudiesThe adsorption of the biosurfactant in sandstone was determined by mixing 2 g of crushed sandstone core samples with 30 mL of biosurfactant solution at a range of concentrations (100, 500, 1,000, 5,000, and 10,000 mg/L). The mixtures were kept in a

TABLE 1—COMPOSITION OF THEPRODUCTION MINIMAL MEDIUM

Composition Concentration (g/l)

0.02 esoculG

NH4NO3 200.4

KH2PO4 380.4

Na2HPO4 911.7

MgSO4 791.0

CaCl2 77000.0

FeSO4.7H2 1100.0 O

MnSO4.4H2 76000.0 O

84100.0 ATDE-aN

TABLE 2—COMPOSITION OF FORMATION WATER

Component Concentration (kg/m3)

380.52 muidoS 267.3 muiclaC 878.0 muisengaM 540.0 norI 227.74 edirolhC 742.0 etahpluS

0 etanobraC 970.0 etanobraciB

TABLE 3—CRUDE-OIL CHARACTERISTICS

Density (g/cm3) Viscosity (cp) API Gravity TAN Salt Content (ppt)

0.838 1.77 36.51 0 12

212 April 2012 SPE Reservoir Evaluation & Engineering

shaker at 160 rev/min and were left to reach equilibrium for 1 week at 40°C. However, they were hand-shaken every 24 hours to ensure thorough mixing of the solid into the solution. After the equilibrium was reached, the mixtures were centrifuged at 6,000 rev/min for 15 minutes at 20°C to separate the clay. The superna-tants were collected, and final concentrations of the biosurfactant in the solutions were determined. The tests were conducted three times, and the average values are reported. The amount of biosur-factant adsorbed per gram of solid was calculated by Eq. 4:

� =−M C C

Ms i f

R

( ). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4)

Results and DiscussionCorefl ooding Experiments. Table 4 summarizes the Berea-core-plug volumetric conditions after the waterfl ood stage and before injection of surfactants for tertiary recovery. Extra recovery from residual oil was observed after the tertiary stage by injecting biosurfactant, chemi-cal surfactant, or a mixture of both, at different concentrations.

Fig. 1 presents a summary of the coreflooding results, where the percentage of recovery from Sor is plotted against each mixture ratio. The results revealed that a total of 23% of residual oil was produced by the biosurfactant, while the production increased to 30% of residual oil when injecting pure chemical surfactant. How-ever, it was interesting to note that the performance was improved when mixing the biosurfactant with chemical surfactant at all ratios tested, compared with injecting pure solutions. Recovery of up to 50% of residual oil was produced when mixing the surfactants at a ratio of 50:50, while the mixture of 75% biosurfactant and 25% chemical surfactant yielded a similar increased production of 46%. The least production by the mixed surfactants was at the ratio of 25:75 of biosurfactant to chemical surfactant, where the recovery was estimated to be 39%; however, it is still higher than the production obtained by injecting the biosurfactant or chemi-cal-surfactant solutions alone.

Youssef et al. (2007) reported that activity of biosurfactants depends on their structural components, where the 3-hydroxy fatty acid composition of lipopeptides is very important for the biosurfactant activity. They manipulated the biosurfactant activity by changing the fatty-acid composition, knowing the relationship to hydrophobicity/hydrophilicity, of the mixtures with different

biosurfactants and synthetic surfactants, and they achieved an ultralow IFT. Therefore, it is expected that the structure of the biosurfactant used in this study was changed when mixed with the chemical surfactant because probable synergetic effect of biosur-factant/chemical surfactant was observed in enhancing oil recovery when used as mixture, rather than alone.

Contact-Angle Measurements. Contact-angle measurements give a general qualitative indication of the wetting tendencies of the surfaces and fl uids. Fig. 2 shows the contact angles of distilled water and the samples treated with 0.25% (w/v) biosurfactant, which is the yield of the biosurfactant produced by the bacterium, 0.4% (w/v) and 0.6% (w/v), respectively. It was found that the contact angle of distilled water on a smooth surface changes from an initial value of 70.6°±0.3° to 25.32°±0.06° when treated with 0.25% (w/v) of biosurfactant. It was also found that increasing the concentration of the biosurfactant to 0.4% and 0.6% moderately reduced the contact angle further, where the additional decrease was approximately 2.44°.

It is obvious from Fig. 2 that the biosurfactant was able to change the wetting affinity of the surface to distilled water. This shows the potential of this biosurfactant to increase the wettability of the surface toward more water-wet. Additionally, it is shown that increasing the concentration of the biosurfactant to 0.4% and 0.6% (w/v) had a minimal change on the contact angle, where it decreased only by 2.44° compared with the lower concentration. This might indicate that the extent of the wetting alteration does not depend much on the concentration of this biosurfactant. Some researchers reported the importance of surfactant concentration and that it should be above the CMC value to give a considerable change (Standnes and Austad 2000).

AFM Analysis. The evidence of surface-topography changes is clear from the AFM analysis results when graphene layers were treated with 0.25% (w/v) biosurfactant solution. Fig. 3 shows the cross-sectional images of both the control and the biosurfactant-treated samples at 10-µm scanning length. It was found that numer-ous precipitations occur at the graphene surface when compared with the reference image. This might be caused by the adsorption of the biosurfactant molecules on the surface of the graphene layers. Furthermore, the roughness of the entire surface increased signifi cantly from an average initial value of 4.3 to 9.1 nm.

0

10

20

30

40

50

60

BS-100% CS-100% BS+CS (75:25) BS+CS (50:50) BS+CS (25:75)

%S o

r p

rodu

c�on

BS: Biosurfactant, CS: Chemical surfactant

Fig. 1—Summary of coreflooding-experiment results using different surfactant-mixture solutions prepared at ratios of 25:70, 50:50, and 75:25 of biosurfactant to chemical surfactants (BS: biosurfactant, CS: chemical surfactant).

TABLE 4—SUMMARY OF BEREA-CORE CONDITIONS BEFORE TERTIARY FLOOD

Pore Volume, cm3 Soi Sor

11.2 74% 38%

April 2012 SPE Reservoir Evaluation & Engineering 213

This shows the surface modifi cation caused by biosurfactant treatment, where the molecules’ precipitation covers the entire section, including the smaller summits that are not as visible as the larger ones.

Fig. 4 shows the 3D AFM images of the samples tested. The images clearly show the extent of the precipitates peaks, where the maximum peak height increased from 90 to 210 nm when treated with the biosurfactant. Some visible peaks are present in the untreated samples, which might be caused by the mineral compounds present in the medium (Table 1). Because the untreated solution used for the AFM analysis did not contain glucose, the precipitates might be molecules of sodium and phosphate, which make up the second-largest concentration in the composition of the minimal medium.

WI Tests. The WI determination by Amott testing revealed the extent of the wetting alteration caused by biosurfactant treatment. Table 5 summarizes the results, in which the control test (untreated sample) indicated that the cores are relatively strongly water-wet because the WI was calculated to be 0.8. It was found that the biosurfactant reduced the WI in both cases when dissolved in for-mation water and distilled water. However, the wettability changed more toward less-water-wet with the distilled water, where WI was calculated to be 0.57. The effect of temperature on wettabil-ity alteration by biosurfactant was determined by conducting the Amott test of 0.25% (w/v) biosurfactant dissolved in distilled water

at 60°C, which is the average reservoir temperature in Omani fi elds. The temperature effect on wettability alteration was clear, such that WI further decreased to 0.4—signifi cantly less water-wet when compared with the test conducted at room temperature.

Fig. 5 shows the cumulative water imbibed into the core fully saturated with oil (Soi). It is clearly shown that the amount of water spontaneously imbibed into the core when treated with biosurfactant is increased. The volume imbibed was doubled with the biosurfactant dissolved in distilled water from 2.11 to 4 cm3. Furthermore, the rate of water imbibition was much higher in the biosurfactant treatment, where more than 95% of the total volume of water was imbibed by the first 24 hours of the test. For the reference test, the water continuously imbibed into the core until the fourth day of the test before it stabilized. It was also observed that increasing the temperature of the test to 60°C increased the volume of water imbibed. Furthermore, it is interesting to note the water-displacement rate was also increased where the plateau was reached only after 6 hours. A similar observation was reported in previous studies, where an increase in imbibition volume and rate was observed with increasing temperature (Alveskog et al. 1998; Standnes and Austad 2000; Babadagli 2002; Zhang and Austad 2006). Standnes and Austad (2000) conducted their imbibition tests at two different temperatures (40 and 70°C) to test the effect of temperature on spontaneous imbibitions. They found that the imbi-bition rate increased dramatically by increasing the temperature to 70°C, where after 14 days, less than 30% of the oil was produced

(a) (b)

Fig. 3—Cross-sectional images of graphene layers of (a) untreated media and (b) 0.25% (w/v) biosurfactant solution.

(a) Control, theta=70.6°±0.3° (b) 0.25% (w/v) biosurfactant, theta=25.32°±0.06°

(c) 0.4% (w/v) biosurfactant, theta=22.88°±0.05° (d) 0.6% (w/v) biosurfactant, theta=22.51°±0.36°

Fig. 2—Contact-angle measurements of distilled water and the samples treated with different biosurfactant concentrations.

214 April 2012 SPE Reservoir Evaluation & Engineering

from the solution at 40°C while 60% was produced at 70°C. They attributed it to the increased diffusion rate of surfactants.

Similarly, for the oil spontaneous imbibitions, the rate of oil imbibed into the core was much higher with biosurfactant treatment. Fig. 6 shows the cumulative oil imbibed into the core

saturated with water. The volume imbibed with 0.25% (w/v) bio-surfactant in distilled water was much higher such that it increased from 0.12 to 0.7 cm3. This is explained by the wetting-tendency alteration of the rock, where it became less water-wet, which in turn allows more oil to be spontaneously imbibed into the core (Austad and Standnes 2003). The similar case for the effect of tem-perature applies because it reduced the WI even further toward less water-wet; even more oil could be spontaneously imbibed, such that the volume increased from 0.7 to 0.85 cm3 when increasing the temperature to 60°C.

These experiments prove the ability of the biosurfactant to change the wettability of sandstone rock surfaces. It is anticipated that this wettability-alteration phenomenon by the biosurfactant is one of the major mechanisms of MEOR. The combined effects of reduction in IFT and wettability alteration using surfactants have also been discussed in the literature (Hirasaki and Zhang 2004; Kowalewski et al. 2006; Zhang and Austad 2006). Most report that changes in wetting properties are dependent on the initial wetting conditions, such that an initially oil-wet system can result in more water-wet conditions and vice versa (Kowalewski et al. 2006).

Adsorption Studies. Surfactant loss caused by adsorption is a major limitation during surfactant fl ood for enhancing oil recovery because it causes surfactant retention, which affects the economical feasibility of this process (Daoshan et al. 2004). Adsorption of the biosurfactant on crushed cores is shown in Fig. 7. The minimum adsorption levels (0.5–0.6 mg/g) were found to be at the lower concentrations of 100 and 500 mg/L. In the biosurfactant concen-tration range of 500–1000 mg/L, a sharp increase of adsorption was observed to 1.2 mg/g. This remained constant with a further increase in biosurfactant concentration. This is the classic trend for surfactant adsorption, where for concentrations ranging between 100 and 500 mg/L, low surface coverage by adsorbed surfactant monomers takes place (Rosen 2004; Salehi et al. 2006). The sharp increase in adsorption for concentrations ranging between 500 and

(a)

(b)

Fig. 4—3D images of graphene surface of (a) untreated media and (b) 0.25% (w/v) biosurfactant solution.

TABLE 5—WI CALCULATION FOR THE DIFFERENT AMOTT TESTS

Test Vwimb Vwf Voimb Vof WWI OWI WI

Control (25±2°C) 2.11 0.41 0.12 2.80 0.84 0.04 0.80

0.25% in brine (25±2°C) 2.60 0.60 0.50 4.00 0.81 0.11 0.70

0.25% in distilled water (25±2°C) 4.00 1.30 0.70 3.00 0.75 0.19 0.57

0.25% in distilled water (60°C) 5.10 2.20 0.85 2.00 0.70 0.30 0.40

0.00

1.00

2.00

3.00

4.00

5.00

6.00

0 12 24 36 48 60 72 84 96 108 120 132 144Cum

ula�

ve v

olum

e of

wat

er sp

onta

neou

sly

imbi

bed,

cm

3

Time, h

Control (25±2°C)

0.25% biosurfactant in forma�on water (25±2°C)

0.25% biosurfactant in dis�lled water (25±2°C)

0.25% in dis�lled water (60°C)

Fig. 5—Cumulative water spontaneously imbibed into the core, Vw imb, as a function of time for treated and untreated samples.

April 2012 SPE Reservoir Evaluation & Engineering 215

1000 mg/L is caused by the formation of local monolayer or bilayer aggregates on the surface (Salehi and Johnson 2006). The fi nal plateau region where surfactant adsorption becomes nearly con-stant despite increasing biosurfactant concentration corresponds to the maximum surface coverage and begins at the CMC of the surfactant (Anderson 1986; Rosen 2004).

It has been shown that the nature of the adsorption isotherm depends to a large extent on the type of surfactant used (Curbelo et al. 2007). The maximum adsorption of the biosurfactant, 1.2 mg/g, compares very well with that of the chemical surfactant, which experiences loss owing to adsorption generally in a range between 0.5 and 2.5 mg/g of solid (Daoshan et al. 2004).

Conclusions1. The biosurfactant performance in enhancing oil recovery was

increased by mixing with chemical surfactants; the maximum pro-duction went up to 50% of residual oil at a mixing ratio of 50:50.

2. Concentration of the biosurfactant had minimal effect on the extent of the wetting alteration, especially at values higher than CMC.

3. The effect of temperature on spontaneous imbibitions was found to significantly increase the volume of the fluid imbibed as well as the rate of the imbibitions.

4. The biosurfactant was able to alter the wettability of surfaces and rocks. Thus, it is anticipated that the wettability alteration is one of the mechanisms for MEOR by the biosurfactant.

5. Adsorption of the biosurfactant isolated and tested in this work was found to be comparable with that of the chemical surfac-tants.The effect of wettability changes on enhancing oil recovery

was clearly observed in this study, where the wettability affects the fluid distribution in the rock and has a stong influence on the spontaneous-imbibition process for oil recovery. Wettability altera-tion by change in the IFT caused by surfactant or biosurfactant treatment results in changes in the imbibition/drainage behavior, thus enhancing oil recovery.

Nomenclature Cf = fi nal surfactant concentration, mg/L Ci = initial surfactant concentration, mg/L MR = mass of crushed core, g Ms = amount of surfactant solution, mL Soi = initial oil saturation, fraction Sor = residual-oil saturation, fraction Vof = volume of oil forcibly imbibed, cm3

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

0 12 24 36 48 60 72 84 96 108 120 132 144

Cum

ula�

ve v

olum

e of

oil

spon

tane

ousl

y im

bibe

d, c

m3

Time, h

Control (25±2°C)

0.25% biosurfactant in forma�on water (25±2°C)

0.25% biosurfactant in dis�lled water (25±2°C)

0.25% in dis�lled water (60°C)

Fig. 6—Cumulative oil spontaneously imbibed into the core, Voimb, as a function of time for treated and untreated samples.

0.2

0.4

0.6

0.8

1

1.2

1.4

100 500 1000 5000 10 000

mg/L biosurfactant

Γ, m

g/g

Fig. 7—Adsorption of biosurfactant in crushed cores at different concentrations.

216 April 2012 SPE Reservoir Evaluation & Engineering

Voimb = volume of oil spontaneously imbibed, cm3 Vwf = volume of water forcibly imbibed, cm3

Vwimb = volume of water spontaneously imbibed, cm3

Γ = amount adsorbed, mg/L

AcknowledgmentsThe authors would like to thank Rabea Al-Moqbali for his kind assistance in the adsorption tests. Also, special thanks to Salim Al-Harthy and Amal Koraa for conducting the AFM runs. Finally, thanks to Ike Siruno for his technical help in running the Amott tests. Appreciation also goes to the EOR Research Center team at Shiraz University (Farhad Varzandeh and Mehdi Escrochi) for their help with the coreflooding experiments.

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Hanaa Al-Sulaimani is a PhD student at Sultan Qaboos University, with research interests in the area of microbial enhanced oil recovery and its potential in Omani oil reservoirs. He holds a BSc degree from Sultan Qaboos University and an MS degree from the University of Adelaide, both in petroleum engineer-ing. He is a member of SPE and participated in the 2010 SPE Student Paper Contest.

Yahya Al-Wahaibi is an assistant professor of petroleum engi-neering and Head of the Petroleum and Chemical Engineering Department at Sultan Qaboos University. email: ymn@squ.edu.om. His research interests encompass the enhanced oil recovery of heavy and conventional oils and multiphase flow in pipelines. Al-Wahaibi holds a BS degree from Sultan Qaboos University, an MS degree from Heriot-Watt University, and a PhD degree from Imperial College London, all in petroleum engineering.

Saif Al-Bahry is an associate professor of biology and Dean of the College of Science at Sultan Qaboos University. Al-Bahry’s research interests include molecular biology and biotechnol-ogy. He holds a BS degree in botany from the University of the United Arab Emirates, an MSc degree in molecular microbi-ology from the University of Wisconsin, and a PhD degree in molecular microbiology from the University of New Hampshire.

Abdulkadir Elshafie is a professor of biology at Sultan Qaboos University. His main research interests are microbiology of oil and environmental microbiology. He holds BS and MSc degrees from the American University of Beirut and a PhD degree from Exeter University.

April 2012 SPE Reservoir Evaluation & Engineering 217

Ali Al-Bemani is an associate professor of petroleum engineer-ing and Vice-Chancellor of Sultan Qaboos University. His main research interest is multiphase flow in porous media. Al-Bemani holds a BS degree from the University of Texas at Austin, and MS and PhD degrees from the University of Southern California, all in petroleum engineering.

Sanket J. Joshi has been working as a postdoctoral researcher on a microbial enhanced oil recovery project at Sultan Qaboos University since 2009. His research interests include microbial enhanced oil recovery, bioremediation, fermenta-tion technology, and microbial metabolites. He has more than 9 years of experience in industrial research and development in microbial fermentations. He holds a degree from Sardar

Patel University, India, and a PhD degree in microbiology from the M.S. University of Baroda, Gujarat, India.

Shahab Ayatollahi is a professor of chemical and petroleum engineering at Shiraz University and the Sharif University of Technology in Iran. email: shahab@shirazu.ac.ir. He is cur-rently the director of the Enhanced Oil Recovery Research Center at Shiraz University, one of the leading EOR centers in the Middle East. His research interests include flow in porous media and enhanced oil recovery techniques in fractured reservoirs. Ayatollahi holds BS and an MS degrees in chemi-cal engineering from Shiraz University, and a PhD degree in chemical engineering from the University of Waterloo, Canada.