Experimental Investigation of Biosurfactant Mixtures of

Surfactin Produced by Bacillus Subtilis for EOR

Application

Nanji J. Hadiaa,∗, Christoph Ottenheima,∗, Shidong Lia,∗, Ng Qi Huaa,∗,Ludger Paul Stubbsa,∗, Hon Chung Laua,b,∗

aInstitute of Chemical Engineering Sciences, Agency for Science, Technolgy andResearch (A*STAR), Singapore 627 833

bDepartment of Civil and Environmental Engineering, National University of Singapore,Singapore 117576

Abstract

Surfactant flooding process is one of the chemical methods widely used for

enhanced oil recovery (EOR) from petroleum reservoirs that utilizes chem-

ically synthesized surfatants. Such surfactants are not bio-degradable and

hence pose environmental concerns. Because of stringent environmental re-

strictions, it is a high time for petroleum exploration and production industry

to move towards biosurfactants. Since biosurfactants are generally more ex-

pensive than chemical surfactants, one of the ways to reduce its cost is to

use fermentation extracts which contain significant amount of biosurfactants

know as surfactin. Surfactin is a cyclic lipopeptide produced by various

strains of Bacillus subtilis. In this work, a lyophilized surfactin extract pro-

duced by Bacillus subtilis organism was evaluated for its potential in EOR

application as an alternative to chemical surfactants. The surfactin mixture

∗Corresponding author. Phone: +65 6796 3908; fax: +65 6873 4805Email address: hadianj@ices.a-star.edu.sg (Nanji J. Hadia)

Preprint submitted to FUEL February 18, 2019

was produced by fermentation and characterized by liquid chromatography-

mass spectroscopy (LC–MS) and matrix-assisted laser desorption/ionization

time–of–flight mass spectrometry (MALDI–TOF MS) techniques. Interfa-

cial tensions (IFT) between two light crude oils and aqueous phases were

measured. Wettability alteration potential was evaluated by contact angle

measurements. EOR performance was evaluated by oil/water displacement

experiments at room conditions using a glass micromodel and sandstone rock

samples. The analysis showed presence of surfactin containing nearly 80%

of surfactin C. IFT measurements showed a significant reduction in IFT in

the presence of surfactin. Contact angle measurments showed alteration of

wettability of glass surface from near neutral–wet to water–wet condition.

Coreflooding experiments on Berea sandstones showed about 1.7–5% incre-

mental oil recovery by surfacin flooding. Glass micromodel experiment also

showed reduction in residual oil and oil–in–water emulsions after surfactin

injection.

Keywords: bio-surfactant, coreflooding, glass micromodel, interfacial

tension, enhanced oil recovery

1. Introduction1

Petroleum reservoirs undergo three different stages of oil production namely,2

primary, secondary (or waterflooding), and tertiary recovery. The primary3

recovery stage uses the natural pressure of energy of the reservoir that can4

produce about 10% of oil present in a reservoir. Further oil production is im-5

proved by injecting water or gas to maintain the reservoir pressure which can6

produce 20-40% more oil. These methods are generally referred as secondary7

2

recovery methods. The amount of oil left over after secondary recovery is8

called residual oil saturation (Sor) that remains a target for EOR. A detailed9

classification of EOR methods can be found in Thomas (2008). The time of10

implementation of a suitable EOR method for a field ultimately depends on11

the economics of the production process. Hence, based on economic evalua-12

tion, EOR can be applied at an early stage after primary recovery if sounds13

economically beneficial. Chemical EOR methods involve injection of suit-14

able chemicals such as alkalis, polymers, and surfactants either individually15

or in combination to alter the properties and/or interactions between crude16

oil/brine/rock (COBR) to increase the oil production. Surfactant EOR is one17

of the chemical enhanced oil recovery (EOR) methods that is being widely18

considered to increase oil recovery from depleting reservoirs.19

It is well established that low IFT between oil and water is the primary20

requirement to mobilize the residual oil and increase microscopic sweep effi-21

ciency and surfactants are mainly used for this purpose (Green and Willhite,22

1998). Traditionally, synthetic and non-biodegradable surfactants are used23

for this application due to relatively lower costs. However, due to stringent24

environmental restrictions, it is a high time for petroleum exploration and25

production industry to move towards biodegradable or biosurfactants that26

are environmentally friendly and yet cost effective. Since biosurfactants are27

generally more expensive than chemical surfactants, it makes such enhanced28

oil recovery (EOR) projects commercially less viable. One of the ways to re-29

duce the cost of biosurfactants is to use fermentation extracts which contain30

significant amount of pure biosurfactants. Such biosurfactant injection for31

EOR can be termed as ex–situ microbial EOR (MEOR) method in which32

3

biosurfactants are produced in the laboratory and injected into the reservoir.33

On the other hand, the in–situ method involves identifying suitable microor-34

ganisms present in the oil reservoir and provide them supporting conditions35

to produce desired metabolites such as biopolymers, biosurfactants, etc. to36

produce desired effects for EOR. Several successful in–situ MEOR projects37

at pilot scale have been executed in onshore fields in India (Woodward, 2006)38

and some field scale projects world–wide (Bryant, 1996; Ariadji et al., 2017;39

Thrasher et al., 2010) where a substantial increase in oil production has40

been achieved. Lal et al. (2009) developed a mixed microbial strains possess-41

ing anaerobic, barophilic,and hyper thermophilic properties for EOR which42

can sustain up to 90◦C and was successfully tested by in–situ field trial. In-43

terest in the microbiology of oil fields is on the upswing because of the need44

to extend the life of older fields, and indications that a better understanding45

of the microbiology of a reservoir can help do that (Rassenfoss, 2011).46

Two types of biosurfactants; glycolipids and lipopeptides have largely47

been studied for MEOR applications. Lipopeptides are reported to be more48

effective in reducing surface and interfacial tensions (Geetha et al., 2018).49

Surfactin, a lipopeptide surfactant produced by Bacillus strains, is an ef-50

fective biosurfactant with high surface activities and exhibits low critical51

micelle concentrations (CMC) as compared to synthetic surfactants (Arima52

et al., 1963; Shaligram and Singhal, 2010). Lower CMC characteristic of the53

surfactin can be attractive for EOR applications as it directly impacts the54

economics of EOR projects. They also exhibit good chemical stability at55

high temperature, pH and salinity conditions (Banat et al., 2010).56

Oil-water IFT values of as low as 0.1 mN/m have been reported in the57

4

literature (McInerny et al., 2003; McInerney et al., 1990; Thomas et al., 1993;58

Ghojavand et al., 2008) for lipopeptides. However, the major drawbacks of59

such lipopeptide surfactants are its low yield and high production costs when60

produced via fermentation. Hence, surfactins have been restricted mainly to61

industries like health care, food, paper and pulp, etc. and barely used for62

EOR application at pilot or field scale. Recently, there have been efforts63

to increase the production yield of surfactin by synthetic biology based on64

promotor exchange using promoters which has increased the yield to 9 g/L65

in 5L fermenters (Jiao et al., 2017; Wang et al., 2018). A surfactin also can66

strongly stabilize emulsions above neutral pH condition and it is feasible to67

recover it from the produced water (Long et al., 2017). Sen (2008) and68

Geetha et al. (2018) have presented an extensive literature survey on various69

production technology for biosurfactants and its potential applications to70

EOR.71

Joshi and Desai (2013) produced crude surfactin by five Bacillus strains72

and tested them for MEOR applications in a sandpack flooding experiment73

at room conditions. They observed 30–34% of waterflood residual oil recov-74

ery. Coreflooding experiments by Al-Wahaibi et al. (2018) showed about 18%75

reduction in residual oil saturation of a Middle East heavy oil by biosurfac-76

tant produced by B. subtilis strains. Fernandes et al. (2016) obtained an77

IFT of 0.07 mN/m between a crude oil and a cell free cultured supernatant78

and high residual oil recoveries with the biosurfactant concentrations used79

at high salinity of 12% NaCl. They also demonstrated good thermal stabil-80

ity of IFT with high temperature up to 75◦C. Liang et al. (2007) evaluated81

biosurfactant produced from agriculture process waste streams to improve82

5

oil recovery in fractured carbonate reservoirs. They observed that biosur-83

factant significantly reduced the IFT between crude oil and brine and was84

very effective in altering the wettability of carbonate rock from oil–wet to85

water–wet.86

Zhang et al. (2016) investigated the surfactin mixture produced by B.87

atrophaeus 5-2a for its potential to increase oil recovery. They tested the88

stability of the surfactin mixture under a wide range of temperatures, pH,89

and salt concentrations and oil removal efficiency was evaluated using sand90

contaminated by crude oil. Seow et al. (2018) derived a highly biodegradable91

nonionic surfactant from tannic acid and evaluated IFT reduction using a92

microfluidic device. Their microfluidic displacement experiment showed more93

oil production with biosurfactant than with sodium dodecylsulphate (SDS).94

This paper reports a systematic experimental investigation to evaluate95

the potential of surfactin as an alternative to chemical surfactants for EOR96

application. The paper presents a comprehensive study from production97

of surfactin to its performance evaluation by laboratory scale oil recovery98

experiments. The performance evaluation was carried out by (i) IFT mea-99

surements between crude oils and surfactin solutions, (ii) flow visualization100

of oil displacement by water/surfactin solutions at pore scale by using glass101

micromodels, and (iii) coreflooding on Berea sandstone samples using crude102

oils and synthetic brine.103

6

2. Materials and Methods104

2.1. Surfactin production and characterization105

For obtaining surfactins, a lysogeny broth (10 g/l tryptone, 5 g/l yeast106

extract, 5 g/l NaCl) was inoculated with Bacillus subtilis 22.2 and grown107

overnight at 30◦C under shaking at 200 rpm in 100 ml conical flasks. The fer-108

mentation product containing a mixture of surfactin isomers was centrifuged109

to separate cells and the supernatant. Subsequently, the supernatant was110

acidified to pH 2 and let stay at 4◦C overnight for precipitation. The pre-111

cipitate was centrifuged, the supernatant discarded and the precipitate re–112

dissolved in distilled water while adjusting the pH to 8. The resulting solution113

was freeze-dried to obtain a powdery formulation for storage and subsequent114

use.115

For characterization of the surfactin mixture, matrix–assisted laser des-116

orption/ionization time-of-flight mass spectrometry (MALDI–TOF MS) and117

liquid chromatography mass spectrometry/mass spectrometry (LC–MSMS)118

was employed. For the MALDI-TOF MS analysis a Bruker autoflex speed119

MALDI TOF was used. The matrix 2,5-dihydroxy benzoic acid was dis-120

solved in water till saturation and mixed with an equal ratio with methano-121

lic lipopeptide extract either obtained from the earlier produced surfactin122

powder or from a thin–layer chromatography (TLC) plate showing distinct123

lipopeptide bands. The mixture was blotted on the MALDI–TOF MS car-124

rier plate and let dried. A PubChem Compound Database (https://www.125

ncbi.nlm.nih.gov/pccompound) was used for surfactin reference. PubChem126

compound IDs 70789014, 46226665, 44227775, and 70789015 were used to127

reference surfactin A, B, C, and D, respectively.128

7

For the LC–MSMS analysis an Agilent 1290 Infinity II UHPLC System129

and an Agilent 6545 Q–TOF mass spectrometer with electrospray ionization130

(ESI) source were used. The UHPLC oven was heated at 40◦C with an131

AdvanceBio Peptide Map column (2.1× 100 µm, 2.7 µm particle size) and an132

injection volume of 2 µl and 5 µl sample for the MS and the targeted MSMS,133

respectively. The flow rate was adjusted at 0.4 ml/min with a mobile phase134

mixture of water and methanol. Both phase compounds were acidified with135

0.1% formic acid. The gradient protocol was 10% water at 0 min, 10% water136

at 2 min, 70% water at 4 min, 100% water at 10 min, 100% water at 12 min,137

10% water at 12.1 min and a stop time at 15 min. As a software interface138

the Agilent Mass Hunter Suite was used for analysis.139

2.2. Porous medium140

Cylindrical Berea sandstone samples designated as BSS–1 and BSS-2 were141

chosen as natural porous media for coreflooding experiments. The length and142

diameter of the sample were 100 mm and 38 mm, respectively. The porosity,143

ϕ, of the sample was measured by vacuum saturation method. The sample144

was first evacuated using a vacuum pump for about 4 hours and then was145

allowed to imbibe a brine of known density, ρ for about 12 hours. The dry146

weight, Wdry and saturated weight, Wsat of the samples were measured and147

the porosity was calculated based on the following equation.148

ϕ =Wsat −Wdry

ρ(1)

To measure absolute permeability, ka, of the samples, the brine was in-149

jected at constant injection rate (Q) and the steady–state pressure drop (∆P )150

8

was measured across the length (L) of the sample. The permeability was then151

calculated from the Dacy’s law as below.152

Q = −kaA

µ

∆P

L(2)

In Eq. 2, A is the cross–sectional area of the sample through which the153

fluid flows and µ is the dynamic viscostiy of the fluid. Connate water satu-154

ration, Swc, was then established by forcing crude oil into the core sample to155

displace the brine by using a porous plate method (Kalam et al., 2006). The156

core samples at this condition was then placed in an oven at 70◦C for two157

weeks for ageing to achieve a representative wettability condition. At this158

stage, the core samples were ready for oil recovery experiment. Properties of159

Berea rock samples are listed in Table 1.160

2.3. Brine and crude oils161

A representative brine was prepared by dissolving 3 wt% NaCl into de–162

ionized water and filtered through 0.45 µm filter and was used as initial brine163

and injection brine for waterflooding. The density and dynamic viscosity164

measured at 25◦C were 1.0025 g/cc and 1 cP, respectively. Surfactin solutions165

were prepared by dissolving a fixed mass of surfactin powder ranging from166

0.05 to 0.25 wt% in 3% NaCl brine.167

Two stock tank crude oils, designated as Oil-1 and Oil-2 with API gravity168

of about 27.3 and 41.6, respectively were used for IFT measurements and169

coreflooding experiments. For flow visualization experiment, only Oil-2 was170

used. The physical properties, and SARA (saturates, aromatics, resins, and171

asphaltenes) compositions of the crude oils are provided in Table 2.172

9

2.4. IFT and optimum salinity measurements173

IFTs between crude oil–brine and crude oil–surfactin solutions were mea-174

sured at 25◦C using a spinning drop video tensiometer (SVT). A spinning175

drop method (Princen et al., 1967) was preferred over other methods as it176

is suitable for ultra–low IFT values (order of 10−3 mN/m). Three measure-177

ments were performed for each pair of crude oil–surfactin solution and the178

mean of these measurements was considered as a true value with standard179

deviations represented as errors in the measurements. To determine the opti-180

mum salinity, IFTs between respective crude oils and 0.1% surfactin solution181

in NaCl brines of varying salinities were measured at room temperature.182

2.5. Contact angle measurements183

To evaluate the ability of the surfactin to alter the wettability of the rock184

surface, contact angles between a crude oil droplet and glass surface were185

measured at room temperature in brine environment using optical contact186

angle meter (Dataphysics, Germany). A clean microscope glass slide was187

used and two chips of approximately 12 x 12 mm size were cut. Usually the188

glass surfaces are initially water–wet in nature. To alter the wettability, the189

glass chips were aged in crude oil at 70◦C for about three weeks. After the190

ageing, the glass chips were lightly rinsed with toluene to remove free oil from191

the surface followed by air drying. One of the chips was then exposed to 0.1%192

surfactin solution in 3% NaCl brine for three days to allow the interactions193

between surfactin and glass surface. Contact angles were then measured by194

sessile drop method by placing oil drop on a glass surface in 3% NaCl brine195

environment. The measurement was continued for few hours to ensure the196

equilibrium of the system.197

10

2.6. Flow visualization experiment198

Flow visualization experiments were performed to study the pore scale199

displacement of crude oil by water and the surfactin solution. For the ex-200

periment, a glass micromodel with a random pore network was used. Glass201

micromodels are artificial porous media consisting of two glass slides; one202

slide with pore network etched into it and sealed by another glass side. Mi-203

cromodels are kind of ideal porous media with only silica surfaces which is204

not a real representation of an actual reservoir. However, they offer an ad-205

vantage of flow visualization at pore scale whereby some key flow behaviors206

can be visualized and hence help understand EOR mechanisms such as emul-207

sification, wettability alteration, etc. Such observations at a pore scale are208

otherwise not possible in case of coreflooding experiments. The micromodels209

were purchased from Micronit Microtechnologies B.V., The Netherlands and210

were used as received. The experimental apparatus, shown in Fig. 1 consists211

of the glass micromodel, a pump, a CCD (charge-coupled device) camera and212

a light source, a differential pressure transmitter (DPT), and a microscope213

with digital camera.214

During the displacement experiment, images were captured by the CCD215

camera at fixed time intervals and later processed using image processing tool216

to calculate oil/water saturations and oil recovery. First, the micromodel217

was vacuumed followed by 100% saturation by brine. The crude oil was218

then injected to establish connate water saturation (Swc). At this stage, wa-219

terflooding was started and continued until residual oil saturation remained220

unchanged. This was followed by surfactin flooding for EOR. At the end221

of each flooding process, the micromodel was transferred to a microscope222

11

to observe changes in oil/water saturations, microemulsion, etc. at certain223

locations in the micromodel. The differential pressure was continuously mea-224

sured by the DPT and logged to a computer. The experiment was conducted225

at ambient conditions.226

2.7. Coreflooding experiment227

The coreflooding experiments were performed on a Berea sanstone core228

sample using a core flooding apparatus. The schematic of the apparatus is229

shown in Fig. 2. The experiments were performed at 25◦C. For the sample230

with Oil–1, the overburden pressure (P2) and back pressure were 24 barg and231

atmospheric, respectively, whereas for the sample with Oil–2 the respective232

pressures were maintained at 45 and 18 barg. A dual–cylinder positive dis-233

placement pump was drawing a fluid from a drive fluid reservoir and pumped234

into injection fluid (brine/crude oil/surfactin solution) accumulators. In the235

accumulators, the drive fluid and injection fluids were separated by a piston236

to avoid contact with each other. The selected injection fluids were thus237

injected from accumulators to the core plug mounted inside a core holder. A238

flooding rate of 3.06 ml/h was used in order to approximate typical reservoir239

velocity of 1 ft/day. A differential pressure transmitter (DPT) was con-240

nected to the inlet and outlet ends of the core holder to measure the pressure241

drop across the rock sample. The data from the DPT were continuously242

logged into the computer. First, 3 wt % NaCl brine was injected into the243

core sample to mimic waterflooding process and to obtain residual oil satura-244

tion. The waterflooding was continued until oil recovery reached a plateau.245

This was followed by injection of a 0.1 wt% surfactin solution to mimic the246

surfactant EOR process. The cumulative oil recovery was measured using a247

12

accurately graduated oil/water separator.248

3. Results and discussion249

3.1. Surfactin characterization250

MALDI-TOF MS showed fitting peaks for surfactin A, B, C and D251

and their respective adducts especially with sodium as shown in Fig. 3.252

LC-MSMS analysis identified the main surfactin with 82% relative abun-253

dance of the C15 isomers (Surfactin C) with Leucin/Isoleucin, Valin and254

Leucin/Isoleucin followed by a relative abundance of 10.5% and 6.1% of the255

C13 (Surfactin A) and the C14 isomers (Surfactin B), respectively. The C15256

and C16 isomers were found in a low relative abundance of below 1% each.257

MALDI-TOF MS as well as LC-MSMS indicated the presence of mul-258

tiple surfactins in the supernatant with the majority being surfactin A, B259

and C. Isomers are typically differing in the overall length of the fatty acid260

tail and three amino acids at position two, four and seven in the ring struc-261

ture. Here, surfactin C with the amino acids Leucin/Isoleucin, Valin and262

Leucin/Isoleucin and an overall relative abundance of above 80% was found263

to be present. This variant of surfactin typically exhibits a low critical micelle264

concentration (CMC) and low surface tension. The structural clarification is265

important as it was earlier shown that an exchange of one amino acid in the266

peptide head will drastically alter the lipopeptides properties (Bonmatin et267

al., 1995). However, due to the difficulties to separate the isomers from each268

other, research on this topic is limited.269

13

3.2. Interfacial activity and optimum salinity270

A surfactin is known to produce very low surface and interfacial tensions.271

In this study, IFTs were measured between crude oils and surfactin solutions.272

Figure 4 shows the results of IFT measurements for Oil–1 and Oil–2 with273

varying concentrations of surfactin in 3 wt% NaCl brine. The results showed274

a minimum IFT of 0.056 and 0.110 mN/m for Oil-1 and Oil-2, respectively275

at 0.025 wt% surfactin concentration. For comparison purpose, IFT between276

crude oils and brine without surfactin were measured to be 23.2 mN/m and277

10.5 mN/m, respectively for Oil–1 and Oil–2. This shows that the surfactin278

was able to reduce the IFT significantly with just 0.025% concentration. This279

is attributed to inherently lower CMC for such surfactin.280

Antibacterial agents commonly known as biocides are usually added to281

biosurfactant solutions to prevent growth of microorganisms when stored for282

very long time. Hence, it is important to study the effect of presence of283

biocide on IFT. In this study, solution of 1% methanol/nystanin was used as284

a biocide and IFTs were measured between crude oils 0.1% surfactin solution285

with biocide. The results are provided in Table 3. It can be noticed that286

no significant changes in IFT were observed due to addition of a biocide. It287

should be noted that for all other experiments and measurements, no biocide288

was added to the surfactin solutions.289

Long–term chemical stability of surfactants is crucial for EOR applica-290

tions. Hence, we also studied the long–term chemical stability of this sur-291

factin by measuring the IFT between 0.1 wt% surfactin and Oil–1 when fresh292

and after 18 months. Results are provided in Table 4. As can be observed,293

the IFT values were not changed significantly after a very long storage time294

14

of the surfactin which shows its excellent chemical stability and suitability295

for EOR applications.296

The results of optimum salinity measurements for 0.1% surfactin con-297

centration are presented in Figure 5. It can be observed that the optimum298

salinity for Oil–1 and Oil–2 were found to be about 0.5% and 2% NaCl, re-299

spectively as the resulted IFTs were lowest at these salinities. The measured300

IFTs at optimum salinities were about 0.009 mN/m and 0.056 mN/m, re-301

spectively. It is interesting to note that for both the crude oils, the optimum302

salinity is quite different with resultant difference in IFTs as well. This can303

be attributed to different chemical composition of the crude oils (Table 2).304

3.3. Contact angle measurements305

As mentioned earlier, the contact angles were measured between crude306

oil and glass surface with and without surfactin treatment by sessile drop307

method in a brine environment and the results are shown in Figure 6. The308

insets in Figure 6 shows the images of the oil drop on glass surface in brine309

environment. It can be observed that the contact angle remain almost sta-310

ble over the duration of measurement for both the cases. For untreated glass311

chip, the mean contact angle (mean of right and left contact angles) was mea-312

sured to be about 109.5◦which shows that the glass surface became almost313

neutral–wet or much less water–wet after ageing in the crude oil. For surfactin314

treated glass chip, the contact angle was measured to be about 147◦which315

was about 38◦higher than that untreated chip. This demonstartes the ability316

of the surfactin to adsorb on the glass surface and alter its wettability. Since317

surfactin is an anionic biosurfactant with two negative charges on the head318

group (Salehi et al., 2008), the increased water–wetness can be attributed319

15

to two factors: (i) formation of ion–pair between anionic head groups of the320

surfactant molecules and positively charged crude oil components adsorbed321

on the glass surface during ageing, and (ii) adsorption of hydrophilic group322

of anionic surfactant onto the hydrophobic surface as discussed by several323

researchers (Salehi et al., 2008, 2010; Kumar et al., 2017).324

3.4. Micromodel experiments325

Glass micromodels are very useful tools for flow visualization to under-326

stand the flow characteristics at pore level. In the case of EOR studies, it327

helps to understand the displacement of one fluid by another (e.g. oil by328

water or other chemical formulations). In this study, micromodel flooding329

experiment was conducted to investigate the effect of surfactin injection on330

waterflood residual oil saturation and identify emulsification activity. It is to331

be noted that only Oil–2 was used for this experiment. Oil–1 was not able332

to give enough contrast between oil and water and hence was not possible to333

be used. Images acquired by CCD camera were used to calculate oil recovery334

and oil/water saturations.335

Figure 7 shows the sequence of captured and processed images at different336

times during waterflooding and surfactin flooding process. The images were337

processed by Fiji Image J, an open source image processing tool. It can be338

observed that the injected brine is able to uniformly sweep the micromodel339

and no flow diversion was observed. This is mainly because of the comparable340

viscosities of injected brine and the crude oil.341

A noticeable reduction in waterflood residual oil saturation can be ob-342

served after surfactin injection as can be observed in Fig. 7 with about 3%343

additional oil recovery after surfactin flooding. Figure 8 shows microscope344

16

images at 200X magnification captured at certain locations after surfactin in-345

jection. A significant emulsification of waterflood residual oil can be observed346

after injection of surfactin which shows the ability of surfactin to emulsify347

the crude oil. The reduction in Sor by surfactin injection can be attributed348

to the ability of surfactin to emulsify the crude oil as well as reduced IFT.349

Emulsion formation and IFT are in a way interrelated. Very low IFT between350

oil and water is the primary requirement for emulsion formation especially351

in oil reservoirs where no other mechanical forces are present. Lower IFT352

reduces the capillary forces that are responsible for trapping of the oil at353

pore throats in any immiscible displacement process. This trapping is best354

expressed as a competition between viscous forces which mobilize the oil, and355

capillary forces, which traps the oil. Emulsified oil droplets that have smaller356

diameter than the pore throats can easily pass through it and thus be easily357

produced.358

3.5. Coreflooding359

Coreflooding experiments were conducted to investigate the performance360

of surfactin in natural porous medium (a representative of sandstone reser-361

voirs). Experiments were conducted using both crude oils. The Berea sand-362

stone sample with 78% of Oil–1 and 77.1% of Oil–2 present were subjected to363

waterflooding with 3% NaCl brine until the recovery reached plateau. This364

was followed by injection of 0.1% surfactin solution for EOR followed by 3%365

NaCl brine as a chase brine. The oil recoveries and differential pressure re-366

sults are showed in Fig. 10. It should be noted that in these experiments,367

after waterflooding, the flow rate was not increased (bump flood) as in our368

previous experiments with similar sandstone samples, no additional oil re-369

17

coveries have been observed. One example of such coreflooding with similar370

experimental conditions is shown in Fig. 9 where an increase of injection rate371

by five times did not provide any additional recovery.372

The final waterflood recoveries for BSS–1 and BSS–2 samples were about373

58% and 43% of OOIP, respectively. During injection of 0.1% surfactin solu-374

tion in the BSS1-case, surprisingly, no additional oil recovery was observed375

after about 3 PV of injection. However, subsequent injection of chase brine376

resulted in about 1.6% additional oil. This can be attributed to redistribution377

of residual oil within the core sample due to possible emulsion formation dur-378

ing surfactin injection. The differential pressure decreased marginally during379

surfactin and chase brine injection. This is because of reduced amount of oil380

present in the sample and hence less resistance experienced by the injection381

fluid.382

A significant difference in oil recoveries from samples BSS–1 and BSS–383

2 were observed. Even though the initial oil saturations were nearly the384

same for both the samples, the final waterflood recoveries for samples BSS–385

1 and BSS–2 were significantly different. This difference in oil recoveries386

can be attributed to different absolute permeabilities. Even though both387

samples have similar porosities of about 21%, the absolute permeabilities of388

samples BSS–1 and BSS–2 were 293 and 153 md, respectively and hence more389

waterflood oil recovery for the sample BSS–1. Further, higher waterflood oil390

recoveries result into lower Sor and hence less amount of oil available for391

EOR.392

Since no additional oil recovery was observed in this particular exper-393

iment, we decided to perform another coreflooding experiment on Berea394

18

sandstone (designated as BSS-1a) with similar core properties for verification395

purpose and the results are presented in Figure 11. The results showed about396

1.3% OOIP additional oil recovery by surfactin injection post waterflooding397

with a slight decrease in differential pressure. The chase waterflooding did398

not recover any further oil. This additional recovery can be attributed to399

the lower IFT and possible emulsion formation during surfactin injection.400

However, emulsion formation could not be confirmed in the coreflooding ex-401

periment. Lower incremental oil recovery by surfactin injection can be at-402

tributed to already high waterflood recovery of about 60% OOIP and hence403

less target oil for EOR.404

In the case of sample BSS–2, about 5% OOIP additional oil was recov-405

ered by surfactin injection whereas chase brine flooding did not result into406

additional recovery. The differential pressure decreased marginally during407

surfactin and chase brine injection. The additional oil recoveries in samples408

BSS-1a and BSS-2 can be attributed to low IFT in the presence of surfactin.409

The coreflooding results show a good potential of surfactin for EOR appli-410

cations. We, however, suggest further investigations under realistic reservoir411

conditions to evaluate the performance of surfactin for EOR application.412

4. Conclusions413

A comprehensive study was conducted to evaluate the surfactin produced414

by B. Subtilis for its EOR potential. The analysis of produced surfactin by415

HPLC and MALDI-TOF MS showed obvious presence of surfactin isomers.416

The surfactin was able to significantly reduce the IFT between crude oils and417

brine. At room conditions, a minimum IFT of 0.056 mN/m was observed418

19

for Oil–1 with 0.025 wt% surfactin concentration. The flow visualization ex-419

periment showed about 3% reduction in waterflood residual oil saturation by420

surfactin injection. The optimum salinity was found to be crude oil depen-421

dent and hence its chemical composition. Based on contact angle measur-422

ments, it can be concluded that the surfactin is able to alter the wettabilility423

of the glass surfaces from near neutral–wet to water–wet. Glass micromodel424

experiment concluded the ability of surfactin to emulsify the crude oil. Room425

condition coreflooding experiments on berea sandstone samples showed about426

1.3–5% OOIP additional oil recovery by 0.1 wt% surfactin injection. The re-427

sults showed a good potential of the surfactin for EOR application but we428

recommend further investigations under typical reservoir conditions.429

5. Acknowledgments430

The authors would like to acknowledge Science and Engineering Research431

Council (SERC), A*STAR, Singapore for their finanical support. Support432

from colleagues Mr. Lim Chen Chuan and Mr. Lewis Queh for crude oil433

analysis is also acknowledged. The Norwegian Petroleum Directorate (NPD),434

Norway is acknowledged for providing a crude oil sample.435

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25

List of Tables541

1 Properties of Berea rock samples. . . . . . . . . . . . . . . . . 29542

2 Physicochemical properties and SARA composition of stock543

tank crude oils. . . . . . . . . . . . . . . . . . . . . . . . . . . 30544

3 Comparison of IFT between crude oils and 0.1% surfactin so-545

lution with and without biocide. . . . . . . . . . . . . . . . . . 31546

4 Comparison of IFT between Oil–1 and surfactin solution when547

fresh and after 18 months at 25◦C measured by spinning drop548

tensiometer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32549

26

List of Figures550

1 Schematic of apparatus for flow visualization experiments. . . 33551

2 Schematic of apparatus for coreflooding experiments. DPT:552

differential pressure transmitter, BPR: back pressure regula-553

tor, P1: injection pressure, PS: overburden pressure, P2: back554

pressure. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33555

3 MALDI–TOF MS of the surfactin bands of a thin-layer chro-556

matography plate for lipopeptide separation showing the pres-557

ence of surfactin A, B, C, D and their respective adducts.558

PubChem compound IDs 70789014, 46226665, 44227775, and559

70789015 were used to reference surfactin A, B, C, and D,560

respectively. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34561

4 IFT variation with different surfactin concentrations in 3%562

NaCl brine for Oil–1 and Oil–2 at 25◦C measured by spinning563

drop tensiometer. Each measurement is an average of three564

measurements. . . . . . . . . . . . . . . . . . . . . . . . . . . . 35565

5 IFT vs. NaCl concentrations for 0.1% surfactin solution for566

Oil–1 and Oil–2 at 25◦C measured by spinning drop tensiometer. 36567

6 Comparision of contact angles between oil and glass surface568

with and without surfactin treatment. Insets show images of569

oil drop on glass surfaces in 3% NaCl brine environment. . . . 37570

27

7 Comparison of oil saturations (a) at Swc, (b) before water571

breakthrough, (c) at water breakthrough, (d) at waterflood572

Sor, and (e) surfactin flood Sor. The black color represents573

crude oil; white color represents combined glass and aqueous574

phase. Area within blue dotted line represents the area with575

pore network. . . . . . . . . . . . . . . . . . . . . . . . . . . . 38576

8 Microscope images showing emulsification of waterflood resid-577

ual oil after surfactin injection. Images (a) - (c) and (d) were578

taken at 200X and 50X magnifcation, respectively. . . . . . . . 39579

9 Coreflooding experiment showing no additional recovery when580

injection rate was increased ten times. . . . . . . . . . . . . . 40581

10 Oil recoveries and differential pressures during coreflooding582

experiments on Berea sandstone samples saturated with (a)583

Oil–1 and (b) Oil–2. . . . . . . . . . . . . . . . . . . . . . . . 41584

11 Oil recovery and differential pressure during coreflooding ex-585

periments on sample BSS-1a saturated with Oil–1. . . . . . . . 42586

28

Table 1: Properties of Berea rock samples.

Sample no. Crude oil Length Diameter ϕ ka Swc Soi

mm mm % md % %

BSS-1 Oil-1 102.8 38.3 21.0 292 22.0 78.0

BSS-2 Oil-2 102.7 38.3 21.5 153 22.9 77.1

29

Table 2: Physicochemical properties and SARA composition of stock tank crude oils.

SARA composition, %

Crude Density µ Saturates Aromatics Resins Asphaltenes

oil g/cc mPa·s

Oil-1 0.852 2.43 38.5±2.8 56.1±3.1 5.3±0.2 0.1

Oil-2 0.812 1.20 72.4±1.0 24.3±0.8 2.9±0.1 0.3±0.2

30

Table 3: Comparison of IFT between crude oils and 0.1% surfactin solution with and

without biocide.

IFT, mN/m

Crude oil Without biocide With biocide

Oil-1 0.097 0.089

Oil-2 0.119 0.123

31

Table 4: Comparison of IFT between Oil–1 and surfactin solution when fresh and after 18

months at 25◦C measured by spinning drop tensiometer.

Surfactin IFT-Fresh IFT-18

wt % mN/m mN/m

0.05 0.120 0.070

0.075 0.048 0.075

0.1 0.074 0.104

32

Figure 1: Schematic of apparatus for flow visualization experiments.

Figure 2: Schematic of apparatus for coreflooding experiments. DPT: differential pres-

sure transmitter, BPR: back pressure regulator, P1: injection pressure, PS : overburden

pressure, P2: back pressure.

33

Figure 3: MALDI–TOF MS of the surfactin bands of a thin-layer chromatography plate for

lipopeptide separation showing the presence of surfactin A, B, C, D and their respective

adducts. PubChem compound IDs 70789014, 46226665, 44227775, and 70789015 were

used to reference surfactin A, B, C, and D, respectively.

34

Figure 4: IFT variation with different surfactin concentrations in 3% NaCl brine for Oil–

1 and Oil–2 at 25◦C measured by spinning drop tensiometer. Each measurement is an

average of three measurements.

35

Figure 5: IFT vs. NaCl concentrations for 0.1% surfactin solution for Oil–1 and Oil–2 at

25◦C measured by spinning drop tensiometer.

36

Figure 6: Comparision of contact angles between oil and glass surface with and without

surfactin treatment. Insets show images of oil drop on glass surfaces in 3% NaCl brine

environment.

37

Figure 7: Comparison of oil saturations (a) at Swc, (b) before water breakthrough, (c)

at water breakthrough, (d) at waterflood Sor, and (e) surfactin flood Sor. The black

color represents crude oil; white color represents combined glass and aqueous phase. Area

within blue dotted line represents the area with pore network.

38

Figure 8: Microscope images showing emulsification of waterflood residual oil after sur-

factin injection. Images (a) - (c) and (d) were taken at 200X and 50X magnifcation,

respectively.

39

Figure 9: Coreflooding experiment showing no additional recovery when injection rate was

increased ten times.

40

(a)

(b)

Figure 10: Oil recoveries and differential pressures during coreflooding experiments on

Berea sandstone samples saturated with (a) Oil–1 and (b) Oil–2.

41

Figure 11: Oil recovery and differential pressure during coreflooding experiments on sample

BSS-1a saturated with Oil–1.

42