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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.

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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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http://dx.doi.org/10.1016/S0927-7757(97)00378-6

http://dx.doi.org/10.1016/S0927-7757(97)00378-6

8 SPE-169001-MS

Mccaffery, F.G. and Mungan, N. 1970. Contact Angle and Interfacial Tension Studies of Some Hydrocarbon-Water-Solid

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147531-MS. DOI: 10.2118/147531-ms.

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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


δ0-20 h 27.693

2. Siliceous, B-15 Anionic 7 Initial δb-0 h 24.615 54.786


δ0-20 h 20.314

3. Siliceous, B-19 Nonionic 7 Initial δb-0 h 37.694 57.448


δ0-20 h 27.919

4. Carbonate, B-42 Anionic 6 Initial δb-0 h 26.834 80.460


δ0-20 h 6.516

5. Carbonate, B-21 Nonionic 6 Initial δb-0 h 11.002 81.461


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


Co

nta

ct A

ngl

e (

°)


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


Co

nta

ct A

ngl

e (

°)


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


Co

nta

ct A

ngl

e (

°)


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


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


ΔCo

ntac

t A

ngle

(°)


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


ΔC

on

tact

An

gle

(°)


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


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


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


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


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


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


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


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


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


52

46 46

30

3941

37

23

ΔC

on

tact

An

gle

(°)


Anionic A

Nonionic A

0

5

10

15

20

25

30

35

40

45


41

3331

22

27

37

29

15ΔC

on

tact

An

gle

(°)


Anionic B

Nonionic B

0

5

10

15

20

25

30

35

40

45

50


4947

43

31

38

3533

22

ΔC

on

tact

An

gle

(°)


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


52

64

52

46 46

56

30

3

44

3941

37

46

23ΔC

on

tact

An

gle

(°)


Anionic A

Nonionic A

0

10

20

30

40

50

60


45

52

41

3331

50

22

34

43

27

37

29

41

15

ΔC

on

tact

An

gle

(°)


Anionic B

Nonionic B

0

10

20

30

40

50

60


51

59

4947

43

57

31

41

51

38

3533

51

22

ΔC

on

tact

An

gle

(°)


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


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


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


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


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.

spe-169001-ms impact of surfactants for wettability ... · unconventional liquid reservoirs (ulr)...

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