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SPE-169001-MS
Impact of Surfactants for Wettability Alteration in Stimulation Fluids and the Potential for Surfactant EOR in Unconventional Liquid Reservoirs Johannes O. Alvarez, Anirban Neog, Afif Jais, David S. Schechter, Texas A&M University
Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Unconventional Resources Conference – USA held in The Woodlands, Texas, USA, 1-3 April 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessar ily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohi bited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Abstract Wettability alteration in shale formations can be an important factor in improving the performance of hydraulic fracturing
treatments. The use of surfactants in the frac fluid, at proper concentrations, has shown to change wettability in
Unconventional Liquid Reservoirs (ULR) favoring the process of imbibition. This study evaluates and compares the
efficiency of anionic and nonionic surfactants in recovering hydrocarbons in carbonate and siliceous preserved side-wall
core. The techniques developed also open the door for investigation of low concentration surfactants for enhanced oil
recovery (EOR) in ULR.
Contact angle (CA) experiments were performed, using the captive bubble method, to measure the magnitude of wettability
alteration on intermediate to oil-wet ULR core at reservoir temperature (165 °F). Different types of anionic and nonionic
surfactants at field concentrations were used. The results showed that all surfactants lower the CA at the concentration tested.
However, anionic surfactants showed better results as observed by lower contact angles. IFT measurements were also
performed, using the pendant drop and spinning drop methods, at reservoir temperature using reservoir crude oil and anionic
and nonionic surfactants at the same concentrations. The IFT reduction was similar for each type of surfactant compared to
regular frac fluid without any surfactant, but anionic surfactant showed slightly better capability of reducing IFT than
nonionic surfactants.
Computed tomography (CT) scan methods were used to gauge the performance of these surfactants in improving oil
recovery. The magnitude of penetration or imbibition into artificially-fractured ULR cores was studied for both anionic and
nonionic surfactants. Frac fluids containing surfactants were mixed with a dopant salt to trace the movement of these fluids
and measure the penetration numerically. Both, anionic and nonionic, surfactants have higher penetration magnitudes
compared to slick water without surfactant. However, anionic surfactants displaced a higher observable amount of liquid
hydrocarbon from the shale cores. This observation agrees qualitatively with the results observed in the CA experiments
where anionic surfactants showed the lowest contact angles. From the results obtained, it can be concluded that anionic
surfactants alter wettability in these ULR core, giving lower CA, better spontaneous imbibition and higher oil recovery than
nonionic surfactants. These observed wettability changes induced by surfactants mixed in the frac fluids can improve matrix
penetration with spontaneous imbibition which opens further discussions for EOR potential in shale formations.
Introduction
Production from unconventional liquid reservoirs (ULR) has become one the most important sources of energy in the
United States. These ULR have the distinctiveness of being both rock source and reservoir with the characteristic of having
low porosity and ultralow permeability. The use of horizontal wells with multiple high permeability hydraulic fractures has
been a highly successful technique allowing these ultralow permeability reservoirs to create effective paths for hydrocarbons
to flow towards the wellbore and to consequently produce at commercial flow rates.
Adding surfactants into frac fluids can alter matrix wettability. This wettability alteration in shale formations can be an
important factor on improving the performance of hydraulic fracturing treatments. The use of surfactants in the frac fluid, at
proper concentrations, has shown to change wettability in ULR favoring the process of imbibition. Frac fluid imbibition and
subsequent oil expulsion from the matrix into hydraulic fractures favors oil production, and this mechanism can be improved
by adding surfactants which alter rock wettability or/and lower interfacial tension (IFT) (Chen et al. 2001).
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Capillary and gravity forces are responsible for imbibition process and are function of wettability, interfacial tension,
density differences and pore radius (Chen et al. 2001; Mccaffery and Mungan 1970); however, for ultralow permeability
reservoirs, capillary imbibition is the main recovery mechanism for producing hydrocarbons due to the reduced pore size, and
hydraulic fractures enhance an effective matrix-fracture interaction in order to recover oil from the matrix (Babadagli et al.
1999). Wettability affects flow behavior and, when altered, imbibition mobilizes oil because of capillary pressure changes
from negative to positive (Wang et al. 2012). To alter wettability, surfactants solutions are added to frac fluids to shift rock
wettability to water-wet, this enhance imbibition by overcoming capillary forces and letting the water phase to penetrates into
the matrix displacing oil in place (Shuler et al. 2011).
Surfactants are amphiphilic compounds that have both a hydrophobic and a hydrophilic group. Based on their polar head
group, surfactants are most commonly classified in cationic (positive charge), anionic (negative charge) and nonionic (no
charge). In previous studies, cationic surfactants have shown improve oil recovery by wettability alteration in oil-wet chalk
rocks (Austad et al. 1998; Sharma and Mohanty 2013; Zhang and Austad 2005); however, this type of surfactant requires
high concentrations and is too expensive to economically be implemented on the field (Adibhatla and Mohanty 2008; Chen et
al. 2001). In addition, anionic and nonionic surfactants have also been studied in fracture carbonates and chalk reservoirs
effectively shifting wettability and reducing IFT, improving oil imbibition (Adibhatla and Mohanty 2008; Austad et al. 1998;
Babadagli et al. 1999; Chen et al. 2001; Sharma and Mohanty 2013; Wang et al. 2012; Zhang and Austad 2005).
The effectiveness of surfactants can be studied by measuring contact angle, IFT and the magnitude of penetration. Contact
angle, in the presence of two immiscible fluids and a rock surface, is an appraisal of which fluid preferentially adheres to the
rock and provides a measure for wettability of a specific surface (Anderson (b) 1986; Anderson 1986; Dake 1978; Mccaffery
and Mungan 1970; Rajayi and Kantzas 2009). In water-oil-rock system in which water is the denser fluid, the rock is water-
wet when the contact angle is from 0°-75°, intermediate-wet from 75°-105°, and oil-wet from 105°-180° (Anderson 1986).
Cohesive forces among two immiscible liquid molecules are responsible for IFT. Contact angles and IFT are liable for
altering capillary imbibition. However, an increase in surfactant concentration not always translates into more oil recovery,
thus wettability and IFT alteration do not have a linear relationship with surfactant concentration (Adibhatla and Mohanty
2008).
Contact angles can be measured by several methods such as captive bubble, sessile drop, tilting plate, and capillary rise,
among others. In addition, IFT can be measured by pendant drop, sessile drop and spinning drop methods. In the petroleum
industry, contact angle and IFT measurements are commonly done by the captive bubble and pendant drop method
(Anderson (b) 1986; Rajayi and Kantzas 2009). Due to the nature of our experiments in which contact angles and ITFs are
based in the deformation of a drop or bubble in another liquid, captive bubble, pendant drop and spinning drop methods were
used.
Computed-Tomography (CT) technology uses computer-processed x-rays to produce tomographic images of specific
areas of the cores, allowing us to see inside them. CT scan methods combined with core-flooding can be used to analyze the
penetration magnitude or imbibition of the fluids and the amount of produced oil from shale cores at reservoir conditions.
Also, fracturing fluids mixed with a dopant salt enables us to trace the movement of these fluids and measure the penetration
numerically.
Various experiments have been conducted on the study of wettability and IFT alteration using surfactants based on
spontaneous and forced imbibition in carbonate and sandstone reservoirs (Adibhatla and Mohanty 2008; Austad et al. 1998;
Babadagli et al. 1999; Chen et al. 2001; Hirasaki and Zhang 2003; Sharma and Mohanty 2013; Shuler et al. 2011; Wang et al.
2012; Zhang and Austad 2005); however, these experiments have limited application on unconventional reservoirs due to
their ultralow permeability and low porosity values. There is limited literature on the study of combined effect of wettability
and the corresponding IFT alteration effect on imbibition process on core samples from unconventional plays. Wang et al.
(2012) conducted wettability and imbibition experiments on cores obtained from the Middle Member in Bakken Shale using
modified Amott Harvey methods to determine potential to imbibe and displace oil from shale cores. They concluded that
some surfactants altered wettability from oil and intermediate-wet cores towards water-wet, and imbibe to displace more oil
than brine alone improving oil recovery. Also, Shuler et al. (2001) performed experiments on Bakken Shale reservoirs
providing the selection of a proper surfactant that matches local reservoir conditions and enhances oil displacement by
imbibition method.
This study combines the effect of wettability and IFT alteration and the corresponding impact on penetration magnitude
or imbibition in ULR by conducting contact angle experiments, using the captive bubble method, IFT measurement, using the
pendant drop and spinning drop methods, and CT scan technology to evaluate and compare the efficiency of anionic and
nonionic surfactants in altering wettability and recovering hydrocarbons from carbonate and siliceous preserved side-wall
shale cores at reservoir temperature. The results showed that surfactants can alter wettability on shale cores from oil and
intermediate-wet to water-wet and reduce IFT with better performance by anionic surfactants over nonionic surfactants. Also,
by CT scan methods we observed that surfactants improve penetration into the matrix compared to frac fluids without
surfactants favoring oil recovering. However, anionic surfactants recovered more oil than nonionic surfactants indicating that
their capability of changing wettability and reducing IFT influence in frac fluid penetration and consequently oil
displacement.
SPE-169001-MS 3
Methodology
Three types of experiments were performed in this study to comply with the objectives proposed. To evaluate and
compare different surfactants that can alter wettability and enhance frac fluid imbibition in ULR, we measured contact angle
and IFT at reservoir temperature (165 °F); then, to study the penetration magnitude or imbibition of these frac fluids, we used
CT scan methods at reservoir conditions.
Rock and Fluid Properties
The ULR cores that we used are from depths around 6000 ft. to almost 9000 ft. They are preserved side-wall cores, 1-inch
diameter with a varying porosity of 3 to 5%. The pore typing varies from 1 to 7, being 7 the best pore type, and cores have
different lithologies such as siliceous, carbonate and mixed. The pore typing and lithology data of the shale cores is shown in
Table 1 and Table 2. Dead crude oils used were from the same wells as the cores with a viscosity of 40.5 cp and a density of
0.8054 g/cc at 165 °F and 35.77° API for Well F, and 30.0 cp and a density of 0.8080 g/cc at 165 °F and 37.74° API for Well
S.
Surfactants
Four different surfactants, two anionic and two nonionic, were tested at concentrations of 0.2, 1 and 2 gallons per
thousand (gpt). For contact angle, IFT measurements and CT scan experiments, frac fluid contains surfactant, at the
concentration mentioned before, biocide and clay stabilizer at a concentration of 1 gpt. The reason why no other additives are
added into the frac fluids is that that for contact angle and IFT experiments the liquid face must be transparent to be able to
measure the parameters, so the same concentration and additives were maintained throughout all experiments.
Contact Angle Measurements
Contact angle experiments were performed using a Dataphysics OCA 15 Pro apparatus. Samples were cut and polished in
square chips in order to fit in the core base inside the measuring device. Next, samples were cleaned with toluene and
methanol and aged at reservoir temperature for more than 6 weeks. Contact angle measurements were done using the captive
bubble method in which, as shown in Fig. 1, oil is dispensed throughout a capillary needle and the drop is attached to the
shale sample measuring the contact angle between the oil and shale rock into the frac fluid solution. Due to the need that the
frac fluid must be as transparent as possible to see and measure contact angle, frac fluids only used surfactant, biocide and
clay stabilizer. In addition, repeatability and consistency of the measurements were reached by having five to seven trials for
each core depth. Using the temperature control unit of the Dataphysics OCA 15 Pro device, all experiments were performed
at reservoir temperature of 165 °F.
IFT Measurements
IFT experiments were performed using a Dataphysics OCA 15 Pro apparatus by the pendant drop method and a Grace
Instruments M6500 Spinning Drop Tensiometer by spinning drop method at reservoir temperature using reservoir crude oil
and anionic and nonionic surfactants at the same concentrations as contact angle experiments. Pendant drop method bottom
up, as showed in Fig. 2, consisted in dispensing oil from the capillary needle into a frac fluid solution and measuring IFT at
the moment when the drop leaves the needle. In addition, in order to verify low IFT values (less than 2 mN/m) a spinning
drop tensiometer was used. There, an oil drop is inserted inside the sample tube previously filled with frac fluid and rotated to
deform the drop and calculate drop diameters. In both methods performed, density of the crudes and frac fluids at 165 °F was
used to calculate IFT.
Penetration Magnitude by CT Scan Methods
A core-flooding system was designed to be combined with the CT-scanner. The integrated system enabled us to
dynamically visualize the movement of the fluid as it penetrated the shale samples in real-time. After processing the real-time
CT-data, qualitative and quantitative experimental results were obtained, and color-coded relative density images.
The core flood experiments are expected to represent the amount of penetration of different surfactant fluids in the ULR
in hydraulic fracturing jobs. Fig. 3 shows our experimental instrument setup which consists of five components: the injection
system, the core flood cell, HD 200 X-Ray CT scanner, the production system, and the data acquisition system.
The surfactants used in these experiments are anionic and nonionic surfactants, and we also used water to flood the cores
to demonstrate the effectiveness of these surfactants. To enhance the contrast of the fluid penetration in the CT data, dopants
are mixed with these fluids. The dopant used was potassium iodide (KI) added until all fluids have a CT number of 1000 in
its container. General experimental procedures are provided as following:
1. A selected preserved 1-inch core is artificially fractured (cut with a wet-saw) and wrapped in Teflon. Its weight and
dimensions is measured and recorded.
2. The core is loaded into the core holder. A rubber sleeve is used to separate the overburden fluid and injection fluid.
3. Overburden pressure is applied at 1000 psi.
4 SPE-169001-MS
4. The injection lines are assembled to the loaded core holder, and the pre-flooded core is scanned.
5. The fracturing fluid prepared in an accumulator is injected at 600 psi through the core holder. Once the fluid comes
out the other end, the pressured fluid is then sealed.
6. CT scans are taken at different time intervals from 0 hour (immediately after flooding) up to 24 hours (maximum
penetration magnitude).
7. After analyzing data, more fluid is flowed through the core holder at 600 psi to retrieve more oil from the core if the
initial flood in step 4 showed droplets of oil. The oil produced is measured visually.
8. The core holder is disassembled, and the core is taken out to measure the post-flooding weight of the core.
Spontaneous Imbibition Experiments
Spontaneous imbibition experiments were performed to qualitatively investigate the capability of anionic and nonionic
surfactants of imbibing ultralow permeability shale cores. Cores were aged for four months in the well oil at reservoir
temperature. Then, we submerged the cores in anionic and nonionic surfactant solutions at a concentration of 3 gpt to see if
oil can come out of them by free imbibition.
Results and Discussions
The results of each experiment performed are explained next. Using the same anionic and anionic surfactants, wettability
and IFT alteration, and penetration magnitudes were obtained giving consistent results for the ULR analyzed.
Contact Angle Measurements
For well S contact angle results are shown in Fig. 4. Frac water bars in the plots represent the experiments performed
without adding any surfactant to test the original contact angle of the cores before altering wettability. From contact angle
measurements without surfactant, we obtained that all samples are initially intermediate-wet ranging from 86 to 102°. At the
four depths tested, it can be seen that almost all surfactant concentrations of 1 and 2 gpt can vary wettability in shale samples
from intermediate-wet towards water-wet with an experimental error of 1 to almost 5 degrees, except surfactant nonionic A.
Also, lower contact angles, which represent more water-wet behavior, were obtained using anionic surfactants than nonionic
surfactants, at the same concentrations. In addition, Fig. 5 shows number of degrees that each surfactant at different
concentrations can change from the original contact angle at a given depth. Better results are observed using anionic
surfactants which alter contact angle in higher degree than nonionic surfactants. In fact, in some cases such as in sample S-22,
nonionic surfactant A could not change wettability at any concentration. This was attributed to the fact that the surfactant
might get degraded at experiment temperature (165 °F) and its lower solubility in the frac water due to its formulation
containing petroleum naphtha and light aromatics.
The results for well F are shown in Fig. 6. Frac water bars showed that cores at the first three depths tested are
intermediate-wet ranging from 91 to 94° and the deepest core is intermediate to water-wet with an initial contact angle of 70°. For all depths, water-wet behavior was reached using anionic surfactant at all concentrations, when nonionic surfactant
needed higher concentrations (1 gpt and in some cases 2 gpt) to shift wettability towards strong water-wet behavior. Overall,
anionic surfactant decreased more contact angle than nonionic surfactants with experimental error from 1 to 5 degrees. Also,
in Fig. 7, it can be seen that anionic surfactants have higher values of change in contact angle than nonionic surfactants
changing up to an angle of 57 degrees from the initial value in some depths.
In addition, cores were qualitatively classified on having high and low total organic content (TOC) to evaluate surfactant
performance in altering wettability at field used surfactant concentrations. From Fig. 8, it can be seen higher contact angles
changes are achieved in cores with high TOC than in cores having low TOC. Originally, cores with high TOC showed
contact angles more towards oil to intermediate-wet, when surfactants are added to frac fluids the change in wettability is
higher than rocks with intermediate-wet behavior in which the change towards water-wet is less in number of degrees.
Finally, we grouped the results by pore type to investigate if pore size impact wettability changes at field used surfactant
concentrations, and the results are shown in Fig. 9. After several experiments, we could not find a traceable trend that
suggests that contact angle changes can be related to pore size in the samples used. We believe that these results are due to
the fact that when we cut and polished the samples for contact angle experiments, we actually changed the surface pore size
making impossible to correlate these results.
Contact angle experiments are a reliable way to measure wettability changes in core samples; however, special care must
be taken when performing these experiments. From sample preparation to actual measurement, procedures should be
followed to assure results consistency. In addition, experiments should be repeated in several trials to get the most reliable
number.
In summary, anionic surfactant showed better capability to shift wettability from oil to intermediate-wet towards water-
wet than nonionic surfactants at field used concentrations of 1 and 2 gpt. Also, at the same surfactant concentrations, higher
changes in wettability were achieved in cores with high TOC than with low TOC. Last, we could not identify a trend that
suggests that pore size affect in any way contact angle measurements in the experiments performed due to the modification
made to the cores in sample preparation. These observed wettability changes induced by surfactants mixed with frac fluids
SPE-169001-MS 5
can improve matrix penetration with spontaneous imbibition which opens the door for investigation of low concentration
surfactants for EOR in ULR.
IFT Measurements
IFT experiments were also performed using the same previous four different surfactants at reservoir temperature (165 °F)
with three concentrations (0.2, 1 and 2 gpt). For oil from well S, the results are in Fig. 10. Anionic surfactants reduced IFT in
higher values than nonionic surfactants; however, the difference was not very significant at field concentrations of 1 gpt
except for surfactant nonionic A which almost did not reduce IFT. This poor performance of nonionic surfactant A was
attributed to its composition of petroleum naphtha and light aromatics which lower its solubility in water. In Fig. 11 are the
results of IFT experiments for oil from well F in which anionic surfactants perform slightly better than nonionic at field
concentrations of 1 gpt except for nonionic surfactant A. For IFT values lower than 2 mN/m, spinning drop method was also
used to confirm the results obtained by pendant drop method achieving values with a difference of less than 0.3 mN/m.
Conventional theories favor IFT decrease in order to reduce capillary pressure and promote imbibition in the matrix.
However, when wettability of the rocks has been change from oil and intermediate-wet to water-wet in ULR, it is more
suitable for the oil recovery if capillary pressure remains high and the imbibed water remains in the matrix. For these reason
we do not recommend to reduce IFT to very low values in which capillary pressure can be overcome letting scape the
imbibed water.
In short, anionic surfactants reduce IFT in higher degree than nonionic surfactant; however, the reduction at field used
concentration of 1 gpt was very similar for almost all the cases. We believe that a balance between wettability alteration and
IFT reduction by surfactants should be reached at the time of designing a fracturing job in ULR, so when surfactants change
wettability, capillarity pressure does not decrease very much in order to prevent imbibed fluids drain from the matrix.
Penetration Magnitude by CT Scan Methods
Data Processing. When the CT data are obtained from the server, it is loaded into an image processing software. The
software enables us to obtain cross-sectional images of the core. The fluid distribution (penetration magnitude) is calculated
with Eq. 1.
(1)
The base CT number is chosen as the lowest average CT number of the core. In our study we chose the CT number of the
core matrix before the fluid is injected as the base curve. This average base CT number is subtracted from CT t, the CT
number of the core at time t to obtain a rise in CT number which we call the penetration magnitude. Eq. 2 calculates the
initial penetration magnitude which is the CT number rise of the fluid at its first contact with the shale matrix divided by its
total penetration after being left 20 hours under pressured conditions.
(2)
Surfactant Penetration Analysis. Scans were taken before the fluid was injected, immediately after injection (0 hours)
and hourly until 20 hours after injection. Our evaluation of penetration magnitudes consists of the values before, 0 hours and
20 hours which we used to calculate the initial penetration magnitude over total penetration. Table 3 is a tabulated result of
the processed CT image data in the form of penetration magnitudes.
The penetration magnitude is evaluated excluding the fracture from the computation to avoid that the CT number change
of the aperture of the fracture offset the whole core calculation, evaluating only specific areas of the matrix while keeping the
evaluated areas constant throughout the cores at different times. The base curve that we chose is before the fluid is injected,
and the maximum curve is the curve at 20 hours. This enables us to take into account the initial penetration, the spontaneous
imbibition of the fluid at its first contact with the matrix without having to worry about the fluid filling in the fracture
aperture. This data is then normalized over the fluid’s total penetration magnitude to find a percentage of total penetration
that the fluid managed to penetrate at its first contact with the shale matrix. Fig. 12 shows an example of our evaluated area.
Initial penetration values were calculated for cores B in Fig. 13 showing that at 0.1 hours the normalized penetration reached
values as high as 80% for anionic and nonionic surfactants, and almost 35% for tap water.
Anionic Surfactant. Initial penetration calculation from the results of the anionic surfactant in both siliceous and
carbonate shales cores showed that this surfactant is more capable than water in penetrating the shale matrix. In the siliceous
shale, the initial penetration magnitude of the anionic surfactant is about 58%. We obtained a value of 54% in a second
experiment using a different siliceous core. In carbonate cores, the initial penetration magnitude is 80%. The chemical action
happens within the first few minutes of contact between the fluid and the matrix surface as showed in Fig. 13. In Fig. 14, it is
shown the penetration of anionic surfactant in a siliceous shale core and the sequence of fluid in seven cross sectional views
of the core before flooding, 0 hours, 30 minutes, 1 hour, 2 hours, 4 hours and 20 hours after flooding. From there it can be
6 SPE-169001-MS
seen the immediate fluid penetration by the change in CT colors. Also, horizontal views are reconstructed from cross-
sectional scans of the core and shown in Fig. 15 where the same behavior is observed.
In addition, on the siliceous cores evaluated, with the same pore size, anionic surfactants showed higher initial and total
penetration magnitude than frac fluids without surfactants. These results are consistent with the previous results of contact
angle and IFT measurements in which it was shown that the anionic surfactant had the capability of shifting wettability from
intermediate-wet towards water-wet and lowering IFT. This potential of anionic surfactant of changing wettability and
reducing IFT favored frac fluid penetration into the matrix and oil recovering. Fig. 16 shows the oil production from the core
flooding experiments that we conducted. The anionic surfactant was consistently successful in displacing liquid hydrocarbons
from the shale core
Nonionic Surfactant. The initial penetration calculation for nonionic surfactant shows a similar value to the anionic
surfactant of 57% in siliceous shales and 81% in carbonate shales. Also, nonionic surfactants showed better initial and total
penetration magnitude than frac fluid without surfactants. Even though the nonionic surfactant matches its anionic surfactant
in its initial penetration magnitude, the anionic surfactant is superior in producing oil; we observed that only one nonionic
surfactant core flooding was successful in displacing oil from the siliceous core. However, this can be also attributed to the
low penetration magnitude observed on carbonate cores affecting oil recovery. On the siliceous cores, the amount of oil
displaced was about a quarter of a similar core flooded with the anionic surfactant.
This result is further verified by the contact experiments where the nonionic surfactants showed lower capability of
shifting wettability and reducing IFT than anionic surfactants. However, the recovery of oil in one of the core floods also
agrees with the contact angle results that showed that nonionic surfactants at concentrations of 1 and 2 gpt also changed
wettability from intermediate-wet to water-wet. We believe that the chemistry of surfactants in this nonionic fluid did help in
displacing oil, but overall, the nonionic is not as good as the anionic surfactant since its capability of changing wettability that
amplifies the effectiveness of the anionic surfactant in displacing liquid hydrocarbons in these ULR.
Water. When we conducted the experiment with water, the value that we obtained for initial penetration magnitude is
31% in siliceous shale. This value is about half of that of the surfactants, which indicates that the penetrating ability of the
water is less than both surfactants. Furthermore, water was not able to displace any liquid hydrocarbons out of the core. This
led us to conclude that the chemistry of the surfactant and their capability of shifting wettability in the cores and reducing IFT
are in fact important for penetration as well as oil displacement from the matrix.
In summary, frac fluids with surfactants have the capability of changing wettability from oil and intermediate-wet to
water-wet and reducing ITF at proper concentrations in comparison with frac fluids without surfactant, and anionic
surfactants showed better performance than nonionic surfactants in changing contact angles, reducing IFT, and recovering oil
than nonionic surfactants for the shale cores evaluated. Also, these surfactant-matrix interactions occurs in the early times
when fluids make contact with the rock, so the evaluation must take into account the early stages to measure accurately frac
fluids penetration magnitudes.
Spontaneous Imbibition Experiments
Finally, in order to discard the only influence of force imbibition in our experiments and back up our theory that
spontaneous imbibition is in fact taking place in our core flooding experiments at early stages; we submerged aged cores into
frac fluid solutions containing anionic and nonionic surfactant at reservoir temperature. We observed that for the core F-37 in
anionic surfactant, in less than 24 hours, several oil drops came out of the core; this is shown in Fig. 17. Also, the core F-3,
which was submerged in nonionic surfactant, recovered oil but about one third of the amount recovered by the core in anionic
surfactant showing almost none oil drops in the core (Fig. 18). These observed oil recoveries from shale cores demonstrating
spontaneous imbibition opens further discussions for enhanced oil recovery potential in shale formations.
Conclusions
1. Contact angle measurements indicates that the cores analyzed are originally oil to intermediate-wet, and this behavior can
be altered towards water-wet by adding surfactants at concentrations of 1 and 2 gpt. Also, anionic surfactants showed
better performance than nonionic surfactants in changing contact angle in oil shale samples.
2. On the samples analyzed, surfactants seem to change contact angle better in rocks with higher carbon content than lower
carbon content. However, pore size does not seem have a traceable impact on the surfactant performance in changing
contact angle.
3. IFT values decreases as surfactant concentrations increases which could improve water imbibition performance in the
matrix, and anionic surfactant showed better capability of lowering IFT values than nonionic surfactants. However, at
field concentration of 1 gpt, both surfactants showed similar performance.
4. Core flooding and CT scan results shows that surfactants, anionic and nonionic, have higher initial and total penetration
magnitude than frac fluids without surfactants. This is consistent with contact angle experiments, where surfactants have
lower contact angle on the shale core surface compared to frac fluids without surfactants.
SPE-169001-MS 7
5. Water without surfactants fails to drain oil from the core sample. This corresponds with its small initial penetration
magnitude. Both surfactant floods are successful in displacing oil. However, the nonionic surfactant was not as consistent
as the anionic surfactant on producing oil. The anionic surfactant remained consistent throughout the experiments and was
successful in displacing oil.
6. We observe that surfactants are capable of displacing oil from aged cores by submerging them in surfactant solutions
demonstrating spontaneous imbibition in shale cores. Also, anionic surfactant showed better oil recovery than nonionic
surfactants in similar cores.
7. More work is required to better understand the role of the different surfactants in imbibing cores from ULR.
Nomenclature
CTbase = Average CT number of the core before injection
CT0hours = Average CT number of the core at 0 hours of injection
CT20hours = Average CT number of the core at 20 hours of injection
gpt = Gallons per thousand
Superscripts
° = angle degrees
Acknowledgements
The authors would like to thank the Department of Petroleum Engineering and Texas Engineering Experimental Station
(TEES) at Texas A&M University, and Crisman Institute Petroleum Research for funding this work. Also, Dr. Agustin Diaz
and Dr. Zheng Cheng from the Department of Chemical Engineering and Mr. John Maldonado from the Department of
Petroleum Engineering at Texas A&M University for their collaboration on the experimental work.
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Austad, T., Matre, B., Milter, J. et al. 1998. Chemical Flooding of Oil Reservoirs 8. Spontaneous Oil Expulsion from Oil- and
Water-Wet Low Permeable Chalk Material by Imbibition of Aqueous Surfactant Solutions. Colloids and Surfaces A:
Physicochemical and Engineering Aspects 137 (1–3): 117-129. DOI: http://dx.doi.org/10.1016/S0927-
7757(97)00378-6
Babadagli, T., Al-Bemani, A., and Boukadi, F. 1999. Analysis of Capillary Imbibition Recovery Considering the
Simultaneous Effects of Gravity, Low Ift, and Boundary Conditions. Paper presented at the SPE Asia Pacific
Improved Oil Recovery Conference, Kuala Lumpur, Malaysia. Society of Petroleum Engineers 00057321. DOI:
10.2118/57321-ms.
Chen, H.L., Lucas, L.R., Nogaret, L.A.D. et al. 2001. Laboratory Monitoring of Surfactant Imbibition with Computerized
Tomography. SPE Reservoir Evaluation & Engineering 4 (1): 16-25. DOI: 10.2118/69197-pa
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Paper presented at the International Symposium on Oilfield Chemistry, Houston, Texas. Society of Petroleum
Engineers 00080988. DOI: 10.2118/80988-ms.
8 SPE-169001-MS
Mccaffery, F.G. and Mungan, N. 1970. Contact Angle and Interfacial Tension Studies of Some Hydrocarbon-Water-Solid
Systems. Journal of Canadian Petroleum 03 (04). DOI: 10.2118/70-03-04
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at the Canadian Unconventional Resources Conference, Alberta, Canada. Society of Petroleum Engineers SPE-
147531-MS. DOI: 10.2118/147531-ms.
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Reservoir Evaluation & Engineering 15 (6): pp. 695-705. DOI: 10.2118/153853-pa
Zhang, P. and Austad, T. 2005. Waterflooding in Chalk - Relationship between Oil Recovery, New Wettability Index, Brine
Composition and Cationic Wettability Modifier. Paper presented at the SPE Europec/EAGE Annual Conference,
Madrid, Spain. Society of Petroleum Engineers SPE-94209-MS. DOI: 10.2118/94209-ms.
SPE-169001-MS 9
Tables
Table 1—PORE TYPING AND LITHOLOGY DATA OF THE SHALE CORES USED IN CONTACT ANGLE
EXPERIMENTS AND SPONTANEOUS IMBIBITION EXPERIMENTS
Core Lithology Pore size
S-4 N/A N/A
S-10 Carbonate 6
S-22 Carbonate 1
S-30 Siliceous 2
F-2 Mixed 4
F-3 Carbonate 5
F-6 Mixed 5
F-7 Mixed 5
F-34 Carbonate 6
F-37 Carbonate 6
Table 2—PORE TYPING AND LITHOLOGY DATA OF THE SHALE CORES USED IN CORE-FLOODING
EXPERIMENT
Core Lithology Pore size
B-16 Siliceous 7
B-15 Siliceous 7
B-19 Siliceous 7
B-42 Carbonate 6
B-21 Carbonate 6
Table 3— CORE-FLOODING EXPERIMENT INITIAL AND TOTAL PENETRATION MAGNITUDE
RESULTS
No. Core type Fluid Pore size Penetration Magnitude Initial penetration
magnitude (%)
1a. Siliceous, B-16 Water 7 Initial δb-0 h 10.720 31.323
Total δb-20 h 34.224
δ0-20 h 23.504
1b. Siliceous, B-16 Anionic 7 Initial δb-0 h 39.602 58.848
Total δb-20 h 67.295
δ0-20 h 27.693
2. Siliceous, B-15 Anionic 7 Initial δb-0 h 24.615 54.786
Total δb-20 h 44.930
δ0-20 h 20.314
3. Siliceous, B-19 Nonionic 7 Initial δb-0 h 37.694 57.448
Total δb-20 h 65.614
δ0-20 h 27.919
4. Carbonate, B-42 Anionic 6 Initial δb-0 h 26.834 80.460
Total δb-20 h 33.351
δ0-20 h 6.516
5. Carbonate, B-21 Nonionic 6 Initial δb-0 h 11.002 81.461
Total δb-20 h 13.506
δ0-20 h 2.503
10 SPE-169001-MS
Figures
Fig. 1—Experimental setup for measuring contact angle using captive bubble method in which shale sample is
placed the top the sample holder and oil is dispensed from the capillary needle.
Fig. 2—Experimental setup for measuring IFT using pendant drop method in which oil is dispensed from the
capillary needle and IFT is measured when the drop leaves the needle.
Fig. 3—Schematic of the experimental setup: a core-flooding system that can be combined with the CT-scanner to
represent the amount of penetration of different surfactant fluids in ULR hydraulic fracturing jobs.
Shale sample
Capillary Needle
Oil Drop
SPE-169001-MS 11
Fig. 4—Contact angle results for well S at different surfactant concentrations and different depths. Anionic
surfactant showed lower contact angles than nonionic surfactants at concentrations of 1 and 2 gpt.
Fig. 5—Contact angle change with respect to the original contact angle for well S at different surfactant
concentrations and different depths. Anionic surfactant showed higher changes in contact angle than
nonionic surfactants at concentrations of 1 and 2 gpt.
79
85
70
79
86
56
83
45
56
38
83
39
49
0
10
20
30
40
50
60
70
80
90
100
Frac Water Anionic A Nonionic A Anionic B Nonionic B
Co
nta
ct A
ngl
e (
°)
Contact Angle Results S -22
0.2 gpt
1 gpt
2 gpt
6459
51
69
102
48
56
42
51
30
50
35
43
0
10
20
30
40
50
60
70
80
90
100
110
120
Frac Water Anionic A Nonionic A Anionic B Nonionic B
Co
nta
ct A
ngl
e (
°)
Contact Angle Results S -30
0.2 gpt
1 gpt
2 gpt
59
69
5961
100
47
63
42
51
36
56
35
41
0
10
20
30
40
50
60
70
80
90
100
110
120
Frac Water Anionic A Nonionic A Anionic B Nonionic B
Co
nta
ct A
ngl
e (
°)
Contact Angle Results S -10
0.2 gpt
1 gpt
2 gpt
72 72
77
69
86
55 55
43
51
31
51
34
41
0
10
20
30
40
50
60
70
80
90
100
Frac Water Anionic A Nonionic A Anionic B Nonionic B
Co
nta
ct A
ngl
e (
°)
Contact Angle Results S -4
0.2 gpt
1 gpt
2 gpt
41
31
4139
53
37
58
49
64
44
65
59
0
10
20
30
40
50
60
70
Anionic A Nonionic A Anionic B Nonionic B
ΔC
on
tact
An
gle
(°)
Effect of Surfactants in changing CA S -10
0.2 gpt
1 gpt
2 gpt
7
1
16
7
30
3
41
30
48
3
47
37
0
10
20
30
40
50
60
Anionic A Nonionic A Anionic B Nonionic B
ΔC
on
tact
An
gle
(°)
Effect of Surfactants in changing CA S-22
0.2 gpt
1 gpt
2 gpt
38
43
51
33
54
46
60
51
72
52
67
59
0
10
20
30
40
50
60
70
80
Anionic A Nonionic A Anionic B Nonionic B
ΔCo
ntac
t A
ngle
(°)
Effect of Surfactants in changing CA S-30
0.2 gpt
1 gpt
2 gpt
14 14
9
17
31 31
43
35
55
35
52
45
0
10
20
30
40
50
60
Anionic A Nonionic A Anionic B Nonionic B
ΔC
on
tact
An
gle
(°)
Effect of Surfactants in changing CA S-4
0.2 gpt
1 gpt
2 gpt
12 SPE-169001-MS
Fig. 6—Contact angle results for well F at different surfactant concentrations and different depths. Anionic
surfactant showed lower contact angles than nonionic surfactants at concentrations of 1 and 2 gpt.
65
82
66
76
94
56
81
50
64
39
55
42
53
0
10
20
30
40
50
60
70
80
90
100
110
Frac Water Anionic A Nonionic A Anionic B Nonionic B
Co
nta
ct A
ngl
e (
°)
Contact Angle Results F -2
0.2 gpt
1 gpt
2 gpt
55
63
5456
92
5156
50 52
35
44
38
48
0
10
20
30
40
50
60
70
80
90
100
110
Frac Water Anionic A Nonionic A Anionic B Nonionic B
Co
nta
ct A
ngl
e (
°)
Contact Angle Results F -7
0.2 gpt
1 gpt
2 gpt
66
79
5962
91
5660
5248
3944
38
50
0
10
20
30
40
50
60
70
80
90
100
110
Frac Water Anionic A Nonionic A Anionic B Nonionic B
Co
nta
ct A
ngl
e (
°)
Contact Angle Results F-6
0.2 gpt
1 gpt
2 gpt
56
68
55
61
70
53
60
48
55
40
47
39
48
0
10
20
30
40
50
60
70
80
Frac Water Anionic A Nonionic A Anionic B Nonionic B
Co
nta
ct A
ng
le (
°)
Contact Angle Results F-34
0.2 gpt
1 gpt
2 gpt
SPE-169001-MS 13
Fig. 7—Contact angle change with respect to the original contact angle for well F at different surfactant
concentrations and different depths. Anionic surfactant showed better capability to shitting contact angle
towards water-wet with higher contact angle changes than nonionic surfactants at concentrations of 1 and
2 gpt.
29
12
28
18
38
13
44
30
55
39
52
41
0
10
20
30
40
50
60
Anionic A Nonionic A Anionic B Nonionic B
ΔC
on
tact
An
gle
(°)
Effect of Surfactants in changing CA F -2
0.2 gpt
1 gpt
2 gpt
37
29
3836
41
36
4240
57
48
54
44
0
10
20
30
40
50
60
Anionic A Nonionic A Anionic B Nonionic B
ΔC
on
tact
An
gle
(°)
Effect of Surfactants in changing CA Well F-7
0.2 gpt
1 gpt
2 gpt
25
12
32
29
35
31
39
43
52
47
53
41
0
10
20
30
40
50
60
Anionic A Nonionic A Anionic B Nonionic B
ΔC
on
tact
An
gle
(°)
Effect of Surfactants in changing CA F-6
0.2 gpt
1 gpt
2 gpt
14
2
15
9
17
10
22
15
30
23
31
22
0
10
20
30
40
Anionic A Nonionic A Anionic B Nonionic B
ΔC
on
tact
An
gle
(°)
Effect of Surfactants in changing CA F-34
0.2 gpt
1 gpt
2 gpt
14 SPE-169001-MS
Fig. 8—Contact angle changes with respect to the original contact angle for low and high total organic matter
(TOC) at different surfactant concentrations. High TOC cores showed higher contact angle change than
low TOC cores.
Fig. 9—Contact angle changes for different pore sizes varying surfactant concentrations. No apparent trend was
identified that might impact surfactant performance in changing CA.
0
5
10
15
20
25
30
35
High TOC High TOC High TOC Low TOC
35
2930
17
10
25 25
10
ΔC
on
tact
An
gle
(°)
CA Change for different organic content at 1 gpt Well F
Anionic A
Nonionic A
0
10
20
30
40
50
60
High TOC High TOC High TOC Low TOC
52
46 46
30
3941
37
23
ΔC
on
tact
An
gle
(°)
CA Change for different organic content at 2 gpt Well F
Anionic A
Nonionic A
0
5
10
15
20
25
30
35
40
45
High TOC High TOC High TOC Low TOC
41
3331
22
27
37
29
15ΔC
on
tact
An
gle
(°)
CA Change for different organic content at 1 gpt Well F
Anionic B
Nonionic B
0
5
10
15
20
25
30
35
40
45
50
High TOC High TOC High TOC Low TOC
4947
43
31
38
3533
22
ΔC
on
tact
An
gle
(°)
CA Change for different organic content at 2 gpt Well F
Anionic B
Nonionic B
0
5
10
15
20
25
30
35
40
45
50
Pore Size 1 Pore Size 2 Pore Size 4 Pore Size 5 Pore Size 5 Pore Size 6 Pore Size 6
34
46
35
2930
45
17
2
38
10
25 25
16
10
ΔC
on
tact
An
gle
(°)
CA for different pore sizes at concentration of 1 gpt
Anionic A
Nonionic A
0
10
20
30
40
50
60
70
Pore Size 1 Pore Size 2 Pore Size 4 Pore Size 5 Pore Size 5 Pore Size 6 Pore Size 6
52
64
52
46 46
56
30
3
44
3941
37
46
23ΔC
on
tact
An
gle
(°)
CA for different pore sizes at concentration of 2 gpt
Anionic A
Nonionic A
0
10
20
30
40
50
60
Pore Size 1 Pore Size 2 Pore Size 4 Pore Size 5 Pore Size 5 Pore Size 6 Pore Size 6
45
52
41
3331
50
22
34
43
27
37
29
41
15
ΔC
on
tact
An
gle
(°)
CA for different pore sizes at concentration of 1 gpt
Anionic B
Nonionic B
0
10
20
30
40
50
60
Pore Size 1 Pore Size 2 Pore Size 4 Pore Size 5 Pore Size 5 Pore Size 6 Pore Size 6
51
59
4947
43
57
31
41
51
38
3533
51
22
ΔC
on
tact
An
gle
(°)
CA for different pore sizes at concentration of 2 gpt
Anionic B
Nonionic B
SPE-169001-MS 15
Fig. 10—IFT results for well S at different surfactant concentrations. Anionic surfactant reduced IFT at lower
values than nonionic surfactants, but at 1 gpt the effect is similar except for surfactant nonionic A.
Fig. 11—IFT results for well F at different surfactant concentrations. Anionic surfactant reduced IFT at lower
values than nonionic surfactants.
Fig. 12—Example of evaluated area excluding the fracture for penetration measurements.
8.5
16.9
6.1
8.1
18.5
2.1
16.8
2.02.5
0.3
16.5
0.4
2.0
0
2
4
6
8
10
12
14
16
18
20
Frac Water Anionic A Nonionic A Anionic B Nonionic B
IFT
(m
N/m
)IFT results Well S
0.2 gpt
1 gpt
2 gpt
10.0
1.6
12.4
10.4
16.4
1.7
16.516.0
18.2
2.0
18.2
16.5
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
18.0
20.0
Anionic A Nonionic A Anionic B Nonionic B
ΔIF
T (
mN
/m)
Effect of Surfactants in changing IFT Well S
0.2 gpt
1 gpt
2 gpt
9.3
3.5
13.4
10.8
17.0
4.4
16.9
14.4
18.6
4.9
17.9
15.7
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
18.0
20.0
Anionic A Nonionic A Anionic B Nonionic B
ΔIF
T (m
N/m
)
Effect of Surfactants in changing IFT Well F
0.2 gpt
1 gpt
2 gpt
9.6
15.4
5.5
8.1
18.9
1.9
14.5
2.0
4.6
0.3
14.0
1.1
3.2
0
2
4
6
8
10
12
14
16
18
20
Frac Water Anionic A Nonionic A Anionic B Nonionic B
IFT
(mN
/m)
IFT results Well F
0.2 gpt
1 gpt
2 gpt
16 SPE-169001-MS
Fig. 13—Initial penetration values were calculated for cores showing that at 0.1 hours the normalized penetration
reached values as high as 80% for anionic and nonionic surfactants and almost 35% for water.
Fig. 14—The penetration of anionic surfactant in a siliceous shale core is shown in this sequence of fluid in seven
cross sectional views of the core before flooding, 0 hours, 30 minutes, 1 hour, 2 hours, 4 hours and 20
hours after flooding where frac fluids penetrate into the matrix in the early stages of core flooding.
0
10
20
30
40
50
60
70
80
90
100
0.001 0.01 0.1 1 10 100
No
rmal
ize
d p
en
etra
tio
n, %
Time, h
Spontaneous Penetration in B cores
B-16 Anionic B-15 Anionic B-19 Nonionic
B-42 Anionic B-21 Nonionic B-16 Water
Initial Penetration
Fracture
SPE-169001-MS 17
Fig. 15—The penetration of anionic surfactant in a siliceous shale core is shown in this sequence of fluid in seven
horizontal views of the core before flooding, 0 hours, 30 minutes, 1 hour, 2 hours, 4 hours and 20 hours
after flooding where frac fluids penetrate into the matrix in the early stages of core flooding.
Fig. 16—Top left and right are oil produced from anionic surfactant flood. The bottom is oil produced from a
nonionic surfactant flood
Fracture
18 SPE-169001-MS
Fig. 17—Spontaneous Imbibition experiment showing core F-37 before (left) submerging in anionic surfactant
and after 24 hours (right). Several oil drops are in the core.
Fig. 18—Spontaneous Imbibition experiment showing core F-3 at the beginning of the experiment submerged in
nonionic surfactant (left) and after 24 hours (right). No oil in the core, but oil drops floating.