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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: [email protected] (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