Experimental and numerical study of surfactant solution spontaneous imbibition in shale oil reservoirs

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Experimental and numerical study of surfactant solution spontaneous imbibition in shale oil reservoirs Jiawei Tu a, James J. Sheng a,b,∗ a b

Texas Tech University, 807 Boston Ave., Lubbock, TX 79409, USA Southwest Petroleum University, Chengdu, China

a r t i c l e

i n f o

Article history: Received 27 July 2019 Revised 7 October 2019 Accepted 1 November 2019 Available online xxx Keywords: Unconventional Shale EOR Surfactant Hydraulic fracturing Petroleum engineering

a b s t r a c t Experimental and simulation studies have thus far demonstrated that surfactant-based Enhanced Oil Recovery (EOR) is a feasible method to improve recoveries from initially oil-wet or mixed-wet Unconventional Oil Reservoirs (UORs). The summarized principle is that surfactant triggers spontaneous imbibition by either Interfacial Tension (IFT) reduction or wettability alteration. Several related studies have focused on the effectiveness of different surfactants or their combinations on the final oil recoveries from selected rock/fluid samples. However, the relative significance of each mechanism is not clear yet. In this work, by following both experimental and numerical simulation approach, we attempt to separately investigate the effect of IFT reduction and wettability alteration on the performance of surfactant based EOR in UORs. Further, the relative importance of each function is addressed while determining the dominating mechanism. Both experimental and simulation results showed that achieving a water-wet status is crucial for higher oil recoveries in shale and tight reservoirs. The effects of IFT reduction could be detrimental to the recovery once the wettability is altered to water-wet due to a lower capillary driven force. Therefore, to design a successful surfactant EOR case in UORs, a surfactant must have the capability of altering the wetness to a more water-wet status. Meanwhile, maintaining a relatively high IFT is also significant. Results from this paper will provide a general suggestion on surfactant selection to enhance oil recovery in UORs. © 2019 Taiwan Institute of Chemical Engineers. Published by Elsevier B.V. All rights reserved.

1. Introduction Worldwide, unconventional reservoirs are playing an important role in hydrocarbon production. Productions from tight oil plays surpassed 50% of total U.S oil production, and it is projected that the U.S. tight oil production will increase to more than 6 million barrels per day in the upcoming decade [1,2]. However, with multistage fractured horizontal well technology, the oil recovery rate from Unconventional Oil Reservoirs (UORs) declined sharply and was reported to be lower than 10% due to the extremely low matrix permeability [3–5]. Meanwhile, it is being noticed that a large amount of fracturing fluid was being retained inside of the shale formations after hydraulic fracturing operations [6]. While some may concern that the water blockage will cause a significant reduction in relative permeability of hydrocarbon phase, it is believed that the process can be utilized to enhance oil recovery by stimulating the oil expulsion from shale matrix by spontaneous imbibition. In order to stimulate this imbibition process, the surfactant can be the solution.

∗

Corresponding author. E-mail address: [email protected] (J.J. Sheng).

Traditionally, surfactant was used as an injecting additive in the flooding of conventional reservoirs to decrease the interfacial tension (IFT) between aqueous and oleic phases. By doing so, capillary number (Nc) will be increased by orders of magnitude (Eq. (1)) and thus the residual oil saturation was decreased by allowing the oil droplets to pass through the pore throats with less resistance. Whereas in oil-bearing shale formations, due to the ultra-low permeability and poor injectivity, surfactant flooding is an impossible approach. Therefore, most studies of surfactant EOR in UORs have been focusing on the water imbibition [7].

Nc =

vμ σ cosθ

(1)

where σ is the interfacial tension; θ is the contact angle; μ is the viscosity of displacing fluid; v is the displacing Darcy velocity. A few possible mechanisms of water uptake by shales are proposed including capillary imbibition, clay hydration, osmosis effect, and evaporation, etc. [6]. Among all of those, capillary imbibition is considered to be the dominant mechanism. Capillary pressure can be expressed by the Young-Laplace equation:

Pc =

2σ cosθ r

(2)

https://doi.org/10.1016/j.jtice.2019.11.003 1876-1070/© 2019 Taiwan Institute of Chemical Engineers. Published by Elsevier B.V. All rights reserved.

Please cite this article as: J. Tu and J.J. Sheng, Experimental and numerical study of surfactant solution spontaneous imbibition in shale oil reservoirs, Journal of the Taiwan Institute of Chemical Engineers, https://doi.org/10.1016/j.jtice.2019.11.003

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where σ is the interfacial tension; θ is the contact angle; r is the Radius of the pore. Capillary force-driven spontaneous imbibition is effective if the rock is water-wet. For an oil-wet rock, the negative capillary pressure inhibits the oil phase from flowing out. It is unfavorable since most shale formations are reported to be mixed to oil-wet [8–10]. There are two applicable methods to trigger or stimulate the imbibition in oil-wet rocks, which are IFT reduction and wettability alteration. By reducing the IFT, the bond number (NB ) will increase. Bond number is defined as the ratio of gravity or buoyancy force versus interfacial tension (Eq. (3)). The effect of gravity force will be more dominant as the IFT decreases. However, this effect of gravity can be minor in oil-wet UORs due to the extremely low permeability [3]. The other approach is wettability alteration, by altering the wettability from oil-wet or mixed-wet to more waterwet, a favorable positive capillary pressure is obtained. The idea of increasing oil recovery with surfactant by wettability alteration is not new, but the previous studies are focused on carbonate reservoirs. According to previous studies, mechanisms of wettability alteration in carbonates are summarized as the ion-pair effect for cationic surfactants, and double-layers effect for anionic surfactants [11–20].

NB =

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k ρ g

σ

(3)

where, σ is the interfacial tension; k is the permeability; ρ is the density difference between the displacing and displaced fluids. The investigation of the surfactant-based EOR in unconventional reservoirs became active in the recent decade [3,4,9,21-23]. Because of the complex mineralogy and ultra-low permeability of oilwet shales, the experiences from carbonates cannot be arbitrarily copied to unconventionals. Begum, et al. studied the influence of mineralogy, IFT, and initial fluid saturation on wettability and imbibition oil recovery [24]; the potential of wettability alteration and imbibition on liquid-rich shale was also analyzed by using chemical blends [25] and the combinations of surfactants [26]. It was claimed that the imbibition and recovery results are influenced by salinity, and surfactant blends showed better recovery than a single surfactant due to a synergy effect. Alvarez et al. evaluated the performance of different surfactants by measuring the alteration of contact angle, zeta potential, and IFT on core samples from the Permian Basin [27,28]. Spontaneous imbibition experiments were also conducted on those samples and were monitored with a CT scanner for over 100 h. Results showed that an anionic surfactant was most effective for the shale samples. Nguyen et al. conducted spontaneous imbibition experiments on reservoir cores of Bakken Shale and outcrops of Eagle Ford shale, and the results showed that the nonionic surfactant performed best while the anionic surfactant came to the second and cationic surfactant came to the last [29]. In 2017, similar studies were performed by Alvarez et al. on Wolfcamp and Eagle Ford reservoirs samples by using anionic, cationic, and nonionic surfactants. They concluded that the spontaneous imbibition in any samples that submerged in surfactant solutions are better than those in water alone [27]. From their results, cationic surfactants worked best on both Wolfcamp and Eagle Ford cores but anionic surfactants decreased IFT further than cationic surfactants. These studies showed that the best-performed surfactant varies in types and acting conditions from different rock samples. Zhang et al. gathered the results of more than 30 spontaneous imbibition experiments from Wolfcamp and Eagle Ford core plugs and analyzed the effects of Contact Angle represented wettability, interfacial tension, and capillary pressure on final recovery factors. The results showed a negative correlation of the contact angle to the final recovery, which indicated water-wetness is more beneficial to the ultimate recovery in shale; whereas the IFT values didn’t show a consistent correlation in terms of final recovery [30]. From a comparison experimental study of spontaneous imbibition

in conventional and tight oil-wet rocks by Tangirala and Sheng, it is noticed that the highest recovery is achieved by the combination of IFT reduction and wettability alteration in tight rock sample, which further proved the prominence of wettability alteration in low-permeable rock spontaneous imbibition processes [31]. However, the previous studies cannot conclude a universal rule of surfactant selection to all the EOR projects in UORs. Numerical simulation studies of spontaneous imbibition with modeling wettability alteration also started with carbonates first. Delshad et al. used a 3D simulation model successfully history matched Hirasaki and Zhang’s experiment in carbonate core samples [32]. Sheng used a similar model to analyze the effects of wettability alteration and IFT reduction on spontaneous imbibition separately for the first time [18]. It is being noticed that in carbonates, wettability alteration only plays an important role when IFT is high but IFT plays very important roles with or without wettability alteration. When IFT is low, spontaneous imbibition is a gravity-driven process; so, wettability is less important for carbonate samples in comparison. An upgraded model with the properties of shale, such as capillary pressures curves, and relative permeability curves was also studied [3]. From the results, it was concluded that a surfactant with wettability alteration function to keep a relatively high IFT is critical in the shale matrix to stimulate the spontaneous imbibition process. Capillary force is the dominating driven mechanism in shales because the gravity effect is so small. Since the wettability alteration is a slow process, if the IFT is too small, the spontaneous imbibition could take an extremely long time. A field-scale model is upscaled and tested by Saputra and Schechter. The model simulated the IFT reduction and wettability alteration by manipulating the capillary pressure and relative permeability curves instead of a dynamic approach basing on the chemical’s presence [33]. Although the similar topic has been studied for years, the relative importance of those two mechanisms: IFT reduction and wettability alteration haven’t been separately studied by combing experimental and numerical simulation approaches. In this work, spontaneous imbibition experiments were conducted on Eagle Ford core plugs with different surfactant solutions that have a spectrum of IFT values. Properties of each surfactant on IFT reduction and wettability alteration were pre-evaluated by spinning drop method and contact angle method, respectively. Moreover, a corescale model was built using CMG-STARS simulator to investigate the spontaneous imbibition processes. The model is verified with our experimental data, and the impacts of IFT reduction and wettability alteration are quantitatively separated to better understand the essential mechanisms of surfactant-based EOR. This simulation framework enables accurate design and optimization of EOR technology in maximizing hydrocarbon recovery from shale reservoirs. 2. Methodology 2.1. Experimental section 2.1.1. Cores and fluids preparation Core samples used in this study are from Eagle Ford shale outcrops. The dimensions are 2 inches in length and 1.5 inch in diameter. All samples were vacuumed for 3 days before saturated with shale oil under 30 0 0 psi for a week. Samples were aged over a month in our laboratory under room temperature to achieve an initially oil-wet status. The properties of the oil sample are shown in Table 1 and the composition details showed in Table 2 can also be acquired from previous publications [34,35]. Five commercial surfactants were selected based on their performance in IFT reduction and capacities of wettability alteration. The purpose is to screen out a set of surfactant solutions that have the ability of wettability alteration but vary in IFTs. The final

Please cite this article as: J. Tu and J.J. Sheng, Experimental and numerical study of surfactant solution spontaneous imbibition in shale oil reservoirs, Journal of the Taiwan Institute of Chemical Engineers, https://doi.org/10.1016/j.jtice.2019.11.003

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Table 1 Properties of the crude oil sample. Density at 69 °F

Viscosity at 69 °F

API Gravity

0.794 g/cm3

3.66 cp

46.7°API

Table 2 Mole percent data of the crude oil sample. Components

Mole Fraction

Components

Mole Fraction

Components

C3H8 IC4 NC4 IC5 NC5 FC6 FC7 FC8

0.01% 0.00% 0.01% 1.35% 1.35% 4.59% 10.68% 12.30%

FC9 FC10 FC11-12 FC13-14 FC15-16 FC17-18 FC19 FC20

8.34% 8.34% 11.79% 9.41% 6.79% 4.94% 2.15% 1.28%

FC21-22 FC23-24 FC25-26 FC27-28 FC29-30 FC31-36 FC37-40 FC41+

Mole Fraction 2.27% 1.04% 1.73% 1.05% 0.50% 0.95% 0.94% 8.21%

Table 3 Selected surfactant candidates in this study.

SurfactantType of surfactant

Primary component of surfactant

N1 C1 C2 A1 A2

Ethoxylated Alcohol ammonium salt

Nonionic Cationic Cationic Anionic Anionic

Fig. 1. The illustration of Amott Cell.

where σ is the IFT, mN/m; ρ is the density difference, g/cm3 ; D is the measured drop diameter, mm; ω is the angular frequency, rpm.

Alcohol Propoxylate

candidates are two cationic, two anionic and one nonionic surfactants (Table 3). Selected surfactants were further being used in spontaneous imbibition experiments with oil saturated core plugs from the same batch. 2.1.2. Contact angle measurements A drop shape analyzer DSA25 from KRÜSS was used to conduct contact angle measurement by captive bubble method. This method allows us to evaluate the contact angle between surfactant solutions and crude oil directly. One shale core plug from the same batch was cut into thin pieces for wettability measurement. These rock pieces with suitable sizes were polished and then went through the same saturation and aging processes with other core plugs. For each test, the rock piece was firstly hung in the center of the measuring container filled with brine. An oil droplet was then introduced to the bottom surface of shale sample by using a J-shaped needle. The initial wettability can then be determined after the contact angles were stabilized. Consequently, the same piece of rock was submerged into one surfactant solution for 24 h and the measurment procedures were performed again to determine the altered contact angle. The contact angle measurement performance was repeated at least 5 times on each sample and was recorded by ADVANCE software provided by KRÜSS. For each rock piece, the measurement was only conducted with one kind of surfactant solution to exclude any cross contamination. 2.1.3. IFT measurement Spinning drop tensiometer M6500 from GRACE Instrument was used to measure the IFTs. This method is able to determine the range of IFT from 10−6 − 102 mN/m. It allows us to select surfactant solution with IFTs from ultra-low to high. A drop of oil sample was introduced into a capillary tube filled with surfactant solution, it is then horizontally arranged into the spinner and rotated under a set of designated speeds. The diameter and curvature of the drop that is elongated by centrifugal force correlate with the IFT, and can be calculated by the formula [36]:

σ = 1.44 × 10−7 ρ D3 ω2

(4)

2.1.4. Spontaneous imbibition experiment The recovery performance of each selected surfactant was evaluated by spontaneous imbibition experiment in Amott cells (Fig. 1). Amott cell is a common experimental apparatus used in petroleum engineering research for oil recovery evaluation or wettability determination. The cell comes with a rubber cap and a glass cell. Rock-fluid system can be sealed with the rubber cap within the cell; any fluid recovery can be easily captured and measured at the neck with graduated scale. To carry out the spontaneous imbibition experiment, the aged core samples were taken out from the container right before the experiment. The attached oil was wiped out by filter paper from the surface, and the saturated weight was recorded in Table 6. Total saturated oil volume can be calculated as:

Vo_total =

msaturated − minitial

ρo

(5)

where Vo_total is the total saturated oil volume, ml; msaturated is the weight of core after saturation, g; minitial is the weight of core before saturation, g; ρ o is the oil density, g/ml. Core plugs are soaked in designated fluid systems within the Amott cells. Each cell was sealed and placed on a steady lab bench under room temperature for more than 100 days. Readings were performed at least one time per day for the first few weeks then every 2–5 days. For each read, with updated oil volume and the assumption of zero initial water saturation, recovery factor can be calculated by:

RF =

Vo_temp Vo_Total

(6)

where Vo_total is the total saturated oil volume, ml; Vo_temp is the oil volume at each time. 2.2. Numerical simulation section 2.2.1. Model build up The base model was built under a cylindrical coordinate with a two-dimensional radial cross section (r-z) in STARS by CMG. CMGSTARS is a reservoir simulator that can design and evaluate the ef-

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where, σ OM is the IFT between oil and lower phase microemulsion phase; C is the fitting parameter; Vom and Vsm are the volume of oil or surfactant in the microemulsion phase; Vom /Vsm is the solubilization ratio. Therefore, a correlation between surfactant concentration W ) and interfacial tension (σ (χsur OM ) can be constructed. If a set of f relative permeability (Kr) curves and capillary pressure (Pc) curves for different interfacial tensions was given, the IFT reduction effect can be simulated by controlling the surfactant concentration.

Sector 2

2.2.3. Modeling of wettability alteration The effect of wettability alteration is characterized by the adsorption isotherm of surfactant, and it can be described as:

Sector 1 Fig. 2. Permeability distribution of carbonate base model (For interpretation of the references to color in this figure, the reader is referred to the web version of this article.).

sur f =

W C1 ∗ χsur f

C1

sur f = fectiveness of chemical-EOR processes of complex chemical additives. In this study, the base model is homogeneous, and has 18 same sized grid blocks in the r-direction, 24 grid blocks in the z-direction and 1 grid block in the θ -direction. The dimension of r-direction is 0.06 inch, 360° for θ -direction and 0.24 inches for zdirection. As shown in Fig. 2, The central 12 × 1 × 12 blocks in blue color represented the core plug that suspend in the middle of the Amott cell. The rest blocks in red simulated the ambient space in the Amott cell filled with surfactant solutions. These two sectors were marked by sector 1 and 2 for further results analysis. 2.2.2. Modeling of IFT reduction By making a correlation between surfactant concentration and interfacial tension, a lower phase microemulsion can be simulated by CMG-STARS. To manifest the microemulsion phase, LiquidLiquid K-value in CMG-STARS is defined as [37]:

KiAB =

composition of component i in phase A composition of component i in phase B

(7)

The actual phase of A and B will be decided by the reference phase of component i. For a lower phase microemulsion, we can define:

KOW water = KOW surf =

O χwater ≡0 W χwater

O χsur f ≡0 W χsur f

W χoil W KWO = χoil oil = O χoil

 W  sur f = G χsur f

(10c)

where,  surf is the adsorption isotherm of surfactant, gmole/ft3 ; C1 and C2 are adsorbing constants for Langmuir isotherm adsorption. U ) and lower boundary By giving the upper boundary (sur f

L (sur ) of adsorption, a second level of relative permeability f curves and capillary pressure curves can be calculated to generate the final Kr and Pc curves. The Kr and Pc are wettability-

U

U

dependent which is also  surf dependent. Kr sur f and PC sur f correspond to the case that completely water-wetness achieved; L

L

Kr sur f and PC sur f corespond to the scenario of complete oil-wet. The interpopation for Kr and Pc in each grid can be written in a general form as: L sur f

Kr = Kr

L sur f



+

 +

 L  sur f − sur U L f Kr sur f − Kr sur f U L sur f − sur f

(11a)

 L  sur f − sur U L f PC sur f − PC sur f U L sur f − sur f

(11b)

(8b)

A schematic flow chart of the Kr and Pc curves calculation is exW , by changing plained in Fig. 3. Since  surf is also a function of χsur f W , both IFT reduction and wettability alteration effects could be χsur f

(8c)

W is mole fraction of oil in the aqueous in the aqueous phase; χoil O is mole fraction of oil in the oleic phase. In this phase and χoil model, the aqueous phase could also be described as a pseudomicroemulsion phase. W Theoretically, If a table of KWO as a function of χsur is given, a f oil W ) and surfaccorrelation between the solubilization parameter (χoil W ) can be established. Huh proposed a tant solution contents (χsur f good correlation between interfacial tension and solubilization ratio, so Interfacial tension can be described as a function of solubilization ratio [38]:

Vsm

(10b)

+ C2

PC = PC

W is mole fraction of surfactant of surfactant in the oleic phase; χsur f

C

χ

1 W sur f

(8a)

O W where χwater is mole fraction of water in the oleic phase; χwater is O mole fraction of water in the aqueous phase; χsur is mole fraction f

σOM =  2 Vom

(10a)

W 1 + C2 ∗ χsur f

(9)

simulated by controlling one parameter. 2.2.4. Modeling of spontaneous imbibition experiment To simulate the spontaneous imbibition process, the vertical equilibrium is turned off for initialization, and water will imbibe into oil containing blocks to drive oil out because a positive capillary pressure that correlates with the water/oil saturation as given in Fig. 4, once the wettability is changed to water-wet. As mentioned in the wettability alteration section, both IFT reduction and wettability alteration can be affected by adjusting the surfactant concentration, which is convenient for some circumstances. However, since the purpose of this work is to analyze the relative importance of wettability alteration and IFT reduction mechanisms separately, it is unfavorable to define these two processes depending on one same factor. To solve this problem, we defined two chemicals with identical properties as two pseudo components that are able to exist in the aqueous phase. By doing so, the first surfactant (S1) and the second surfactant (S2) can be manipulated separately to affect IFT reduction and wettability alteration.

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Kr and Pc for water-wet rock with Low IFT

Correlation of Wettability alteration on adsorption

Kr and Pc for oil-wet rock with High IFT

Temp Kr and Pc curves for oil-wet rock

Correlation between and IFT

Temp Kr and Pc curves for water-wet rock

Kr and Pc for water-wet rock with High IFT

5

Correlation between and IFT

Kr and Pc for oil-wet rock with Low IFT

Final Kr and Pc curve Fig. 3. Schematic of Kr and Pc curves interpolation.

Table 4 Petrophysical parameters for base model. Oil-Wet

Sor & Swi Endpoint of Kr Kr Exponent Endpoint of Pc (psi) Pc Exponent Permeability (mD) Porosity(%)

Water-Wet

Oil Phase

Water Phase

Oil Phase

Water Phase

0.38 0.59 3.3 −5 2 122 24

0.32 0.23 2.9

0.38 1 2 5 2

0.32 0.15 2

ADS, gmole/2

0.1

0.01

Fig. 4. Capillary pressure curves of oil-wet and water-wet for the base carbonate cases.

To analyze the oil recovery, average water saturation in sector 1 can be read and acquired from the results. The recovery factor from the simulation can be calculated by:

RF =

S¯w − Swi 1 − Swi

(12)

where, Sw is the average water saturation in sector 1; Swi is the initial water saturation in sector 1. 2.2.5. Model validation Delshad et al. and Sheng successfully did history matching on Hirasaki and Zhang’s spontaneous imbibition experiment in oi-wet carbonate with simulator UTCHEM [16,18,32]. In this work, we firstly used the same experimental results to validate our CMGSTARS model. In the ambient blocks, the porosity is 0.999 and the capillary pressure is 0 psi. The permeability is 10 0 0 mD and relative permeability curves are two diagonals. For the core sample blocks, the relative permeability curves and capillary pressure curves are described by Brooks and Corey’s model [39]. Related parameters and petrophysical properties are showed in Table 4. Surfactant adsorption isothermal is shown in Fig. 5 and the upper-bound and lower-bound for wettability alteration are 0.01

0.001 0.001

0.01

0.1

1

Mole Fracon of Surfactant in aqueous phase Fig. 5. Surfactant adsorption curve.

gmole/ft3 and 0, respectively. The relations of solubilization parameter versus surfactant concentration and IFT versus solubilization parameter were adjusted to match the experimental data and were shown in Figs. 6 and 7. As showed in Fig. 8, the simulation results from our CMG model matched the experimental data and UTCHEM results. 2.2.6. Model adjustment To change the base model into a shale-scale model, both result accuracy and running efficiency should be considered. Not only the static properties such as permeability and porosity to be changed, but capillary pressure, relative permeability curves and grid block numbers should be adjusted and refined as well. For the static properties of this shale model, permeability was assigned to 0.0 0 035 mD (350 nD) and the porosity was 7.5% (Table 5a). In order to obtain a higher accuracy of interpolation, a set of 5 relative permeability and capillary pressure curves corresponding to

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Table 5a Static parameters of shale model.

1

Mole Fracon of oil in microeulsion phase

Parameters

0.1 Sor & Swi Permeability (mD) Porosity(%)

0.01

Oil-Wet

Water-Wet

Oil Phase

Water Phase

Oil Phase

Water Phase

0.15 0.00035 7.5

0

0.15

0

0.001

0.0001 0.0001

0.001

0.01

0.1

1

Mole Fracon of Surfactant in aqueous phase Fig. 6. Correlation between surfactant concentration and solubilization parameter.

100 10 1 IFT mN/m

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0.1 0.01 0.001 0.0001 0.00001 0.00001

0.0001

0.001

0.01

0.1

1

Mole Fracon of oil in microeulsion phase Fig. 7. Correlation between solubilization parameter and IFT.

different IFTs were introduced into the simulation model for both oil-wet and water-wet cases. Results of Longeron were considered when setting our relative permeability curves correlated with IFTs [40]. When IFT that is larger than 1 mN/m, relative permeability curves were considered to be the same, but the differences started to appear when IFT further decreased. Two diagonals were considered as the relative permeability curves for ultimate low IFT that equals to 0.001mN/m (Fig. 9). Capillary pressure curves are based on the correlation of Eq. (2). The capillary pressure curves were plotted separately for different IFTs in Fig. 10. The endpoint of Pc is 1450 psi when IFT is high and is 0 when ultra-low IFT (0.001mN/m) was achieved. The capillary pressure values are positive for water-wet cases and negative for oil-wet cases. Details of assigned values are shown in Table 5b and 5c. The sensitivity analysis of grid block numbers was done before any further studies. The original base case has 18 grid blocks in the r direction, 1 grid block in the θ direction and 24 grid blocks in the z-direction. Since the middle 12 × 1 × 12 blocks represent the core sample, we started grid refinement at the outermost layer by 20 times and 10 times (Fig. 11). As shown in Fig. 12, for the model with 20 times grid blocks, the running time is more than 30 min, which is inefficient for our study purposes. However, the model with 10 times grid blocks needed only about 5 min and the result was quite close to the 20 times model when compared with the original case. Therefore, we selected the model with 10 times grid refinement as the final candidate for our shale-based model.

50

40

Recovery Factor, %

Experiment UT-Chem

30

CMG-STARS 20

10

0 0

20

40

60

80

100

120

140

Time, Days Fig. 8. History Matching results of spontaneous imbibition from carbonates.

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Fig. 9. Relative permeability curves for different IFTs of oil-wet(left) and water-wet(right) cases. Table 5b Relative permeability and capillary pressure curves for oil-wet rock. IFT, mN/m

20

1

0.1

0.01

0.001

Phase

O

W

O

W

O

W

O

W

O

W

Endpoint of Kr Kr Exponent Endpoint of Pc (psi) Pc Exponent

0.59 3.3 −1450 2

0.23 2.9

0.59 3.3 −72.50

0.23 2.9

0.7 2.7 −7.25

0.4 2.2

1 2 −0.73

1 2

1 1 0

1 1

Table 5c Relative permeability and capillary pressure curves for water-wet rock. IFT, mN/m

20

Phase

O

W

O

1 W

O

0.1 W

O

W

O

W

Endpoint of Kr Kr Exponent Endpoint of Pc (psi) Pc Exponent

1 2 −1450 2

0.15 2

1 2 −72.50

0.15 2

1 1.7 −7.25

0.4 1.7

1 1.3 −0.73

0.7 1.3

1 1 0

1 1

Table 6 Properties of core samples in the experiment.

0.01

0.001

Table 7 Properties of cores that used in the experiments.

Core Sample

Dry Weight, g

Saturated Weight, g

Weight of total oil, g

Volume of total oil, ml

Solutions Type of surfactant

Applied concentration, wt.%

IFT, mN/m Final contact angle (± 3 ◦ )

EF-1 EF-2 EF-3 EF-4 EF-5 EF-6

123.47 127.32 126.77 126.07 125.96 126.51

127.64 132.56 131.09 131.60 129.54 131.82

4.17 5.24 4.32 5.52 3.58 5.31

5.04 6.34 5.22 6.68 4.33 6.43

N1 C1 C2 A1 A2

1.0 0.5 0.5 0.1 0.1

3.00 0.46 0.18 0.01 0.03

3. Results and discussion 3.1. Experimental studies 3.1.1. Results of surfactant evaluation For the experimental section, information of core samples that before and after oil saturation are shown in Table 6. Results of surfactant evaluation on IFT reduction and wettability alteration are shown in Table 7. Initially, the water-oil interfacial tension was 18 ± 1 mN/m and the contact angles were measured as 133 ± 3 ◦ , which indicated that the samples were oil-wet (Fig. 13).

Nonionic Cationic Cationic Anionic Anionic

50 35 52 33 36

From the results, all the selected surfactant candidates had both IFT reduction and wettability alteration functions. Wettability was altered from oil-wet to water-wet but the extent of IFT reduction are different. The applied concentrations are presented in Table 7. These concentrations are larger than CMC and were determined from surfactant evaluation process so that the spectrum of IFT values can be acquired. Surfactant N1 exhibited the lowest IFT reduction effect; it altered the contact angle to 50° while holding the IFT at 3 mN/m. Anionic surfactant A1 and A2 are most effective in decreasing IFT, and the IFT was measured in the order of 0.01 mN/m. Cationic surfactant C1 and C2 are the medians.

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80

1500 Wat-Wet IFT > 20 mN/m Oil-Wet IFT > 20 mN/m

1000

Wat-Wet IFT = 1 mN/m Oil-Wet IFT = 1 mN/m

60 40 20

0 0

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Pc, Psi

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0 0

0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9

-20

-500

-40 -1000

-60

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Sw

8

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6 4

0.4

2

0.2

0 0

0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9

0 0

-2

-0.2

-4

-0.4

-6

-0.6

-8

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0.6

Pc, Psi

Pc, Psi

Sw

0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9

-0.8

Sw

Sw

1 Wat-Wet IFT < 0.001 mN/m Oil-Wet IFT < 0.001 mN/m

0.8 0.6 0.4

Pc, Psi

0.2 0 -0.2

0

0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9

-0.4 -0.6 -0.8 -1

Sw

Fig. 10. Capillary pressure curves for different IFTs of oil-wet and water-wet cases.

3.1.2. Results of spontaneous imbibition experiments Spontaneous imbibition experiments (Fig. 14) were conducted on those 5 selected surfactant solutions with a cell of water as control group. The results are shown in Fig. 15. From the recovery profile (Fig. 15), it is noticed that the water case, with highest IFT but no wettability alteration effect,

achieved the lowest imbibition rate and the recovery factor over the 120 days. The recovery factor became stable at approximately 10%. Nonionic surfactant N1 with highest IFT and wettability alteration function exhibited the fastest imbibition rate through the beginning to the end, it also showed the highest recovery factor (64%) at 120 days. Two cationic surfactants C1 and C2, with

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Fig. 13. Contact angle measurement for the original wettability (Oil-Wet).

Fig. 11. 10-times refinement shale imbibition model. Fig. 14. Spontaneous imbibition experiment apparatus.

Fig. 12. Sensitivity analysis of grid block numbers on shale model.

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0.7 N1 C1

0.6

C2 A1

Recovery Factor

0.5

A2 Water

0.4

0.3

0.2

0.1

0 0

20

40

60

80

100

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Time, days Fig. 15. Recovery profile of Spontaneous imbibition experiments.

1

Recovery Factor

0.8

EXP-N1

SIM-High IFT- 100%WA

EXP-C1

SIM-Interm IFT- 100%WA

EXP-A1

SIM-Low IFT- 100%WA

EXP-Water

SIM-High IFT- 0%WA

0.6

0.4

0.2

0 0

20

40

60 Time, Days

80

100

120

Fig. 16. Comparison between experimental and simulation results.

intermediate IFT, obtained intermediate recoveries. For anionic surfactant with extremely low IFT, A1 achieved the lowest oil recovery. However, the only exception noticed in the experiments is surfactant A2. Though it exhibited a much lower IFT than C1 and C2, the imbibition was much faster than C2 and similar to C1. This could because of the pre-existing micro-fracture on this core sample. Based on the simulation results summarized the roles of IFT and wettability play on spontaneous imbibition in shale matrix, Sheng proposed that the initial wettability plays an important role in such a scenario. Therefore, a wettability alterable surfactant is

a prerequisite for the success of spontaneous imbibition in oil-wet shale matrix. In addition, because of the slowness of this alteration progress, a high IFT is necessary to make this EOR method practical. Further, due to such an ultra-low permeability, the gravity effect is too small to make any distinctive contribution in a short period of time. Therefore, if the oil-wet nature was intact, it does not matter high or low the IFT is, the EOR attempt will become a fail [3]. In an oil-wet reservoir with higher permeability, for example, most carbonate reservoirs, because of the buoyancy force is able to be prominent, decreasing IFT is important no matter the wettability is altered or not [18].

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Fig. 17. Sensitivity analysis results of interfacial tension.

The experimental results of this study basically verified Sheng’s conclusion from simulation results. Capillary pressure is the most essential driving force to propel the whole imbibition process. In shale oil reservoirs, because of the oil-wet nature and the extremely low permeability, wettability alteration is the rule of thumb to make sure the spontaneous imbibition works. According to Eq. (2), capillary pressure is proportional to the value of IFT. Therefore, a surfactant that has wettability alteration capacity while holding a higher IFT would be the ideal candidate to be used in a surfactant EOR project in UORs. This explained why the nonionic surfactant N1, which has high-IFT and wettability alteration function, obtained the highest recovery while the water case was the worst. The statement will also be verified by CMG-STARS simulation model in the next section. 3.2. Numerical simulation studies 3.2.1. Comparison between experimental and simulation results Four numerical simulation cases were created to match the experimental results from surfactant N1, C1, A1 and water (Fig. 16). These four cases were assigned to be originally oil-wet, but three were able to be altered to water-wet that represented the surfactant system experiments; the one without wettability alteration simulated the brine system. Among the three surfactant cases, high, intermediate, and low IFT corresponded to surfactant N1, C1, and A1 experiments. From the results, final recoveries of three surfactant cases at 120 days were basically matched with the experimental results. However, the initial imbibition rates in our

simulation model were higher than the experiments, this could be due to the differences in wettability alteration effectiveness between the experiments and simulation models. The wettability alteration started as the surfactant molecules entered the matrix pores through diffusion, which is a slow process to initiate the imbibition. In other words, if a surfactant has stronger wettability alteration effect, the difference between the experiment and the simulation results will be smaller. Otherwise, the difference will be larger. Further, during the experiment, the Amott cells were placed at a stable bench to prevent any disturbance, but it also caused some early produced oil that attached to the rock surface wasn’t being counted. As the oil droplets converged to bigger sizes, the oil detached from the surface, and caused the sudden recovery increase on the profile. In the brine water case, simulation result basically showed no oil recovered for the whole period of time. This is because the wettability was not altered, and the capillary pressure was negative. However, in the experiment, capillary imbibition may not the only effect that is responsible for water uptake. Clay hydration, micro-fracturing and osmosis effects etc. could result in a certain amount of water being taken into the shale matrix [6]. 3.2.2. Sensitivity studies: effect of interfacial tension and wettability The effect of IFT was analyzed first. A series of cases were assigned to completely alter the originally oil-wet model to waterwet, but the IFT between oleic and aqueous are different. To differentiate the IFTs, the concentration of component S1 is assigned to values corresponding to different capillary pressure curves. The results are shown in Fig. 17. It is being noticed that the speed of

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Fig. 18. Sensitivity analysis results of wettability.

spontaneous imbibition of oil-wet shale is strongly correlated to the value of IFT. With the same capacity of wettability alteration, the case of 30 mN/m IFT exhibits the fastest imbibition speed and highest oil recovery at 120 days, whereas the case with ultra-low IFT has the lowest recovery, which is less than 1% at 120 days. These results indicated that if a group of surfactants have the same ability to alter the wettability, the one that is able to keep the highest IFT should be the best candidate. The next issue to investigate is the influence of wettability alteration of a surfactant while the IFTs are the same. Since the extent of wettability alteration essentially relates to the concentration of component S2, a series of cases are designed to alter the wettability from 0% to 100%. The 0% case corresponded to the surfactant has no ability to change wetness, which indicates the shale stays originally oil-wet state. Analogously, 50% and 100% would represent the ability to alter the wetness to intermediate-wet and completely water-wet. The IFTs for all cases are equally assigned to 1 mN/m. The simulation results showed in Fig. 18 indicated that the speed of spontaneous imbibition also positively correlated to the extent of water-wetness. It could be explained that the more water-wet state is, the larger the capillary pressure will be, which is favorable for spontaneous imbibition process. Wang and Sheng studied this observation in a micro-scaled pore network model and yielded a similar observation. Their results showed that when the oil-wet fraction is larger than 40%, the recovery factor decreased significantly with the increase of oil-wetness. They concluded that it is due to the significant shrinkage of the positive capillary pressure [41].

In the 0% alteration case, oil recovery is almost zero at 120 days, though the IFT is reduced by approximately 20 times. This didn’t happen in either the simulation or the experimental studies on oil-wet carbonate [18,32]. Our explanation is that the effect of gravity in extremely low permeability is too small to be effective in a short period of time. To investigate the effect of gravity, we designed another two cases to verify our explanation. One case represents the carbonate model with higher permeability (122 md) and the other one stands for a shale matrix (350 nd). Both two cases are oil-wet and assigned with ultra-low IFT between oleic and aqueous phases; the initial water saturation and residual oil saturation were assigned to zero. Therefore, in these two case, the only driving force is gravity, and the results were showed in Fig. 19. Under an ultra-low IFT, gravity is very important for water uptake in carbonate matrix, and the ultimate recovery was reached by 30 days. However, for the shale matrix, such an effect is negligible in a profitable timeframe because the ultimate recovery was reached at almost 10 million days. The results explained the inefficiency of imbibition in shale if it is oil-wet or when the IFT is ultra-low. The final simulation study in this paper is to investigate the combined effect of wettability alteration and IFT reduction on spontaneous imbibition. We designed 8 cases that can be paired into 4 groups. An array of IFT values that vary from 20 to 0.01mN/m were run for 80% and 20% wettability alteration (c.f. Fig. 20). As previously discussed, both wettability alteration and IFT reduction correlate to the spontaneous imbibition speed. high IFT and a more water-wet status achieved the highest recovery within an extremely short period. In addition, it can be observed that for

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Fig. 19. Analysis of gravity effect on carbonate and shale models.

Fig. 20. Combined effects of IFT and wettability.

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any two cases with the same IFT, the final oil recovery is essentially controlled by the matrix wetness status. 4. Conclusions In this study, by combining the experimental and numerical simulation approaches, we separately investigated the roles that IFT reduction and wettability alteration play within surfactant based EOR in UORs. The following conclusions can be drawn to better guide the process of surfactant selection for the industry: 1. The state of water-wetness is critical for shale oil recovery by spontaneous imbibition, and the capillary force is the dominant effect. 2. The final recovery is prominently controlled by the extent of wettability alteration from oil-wet to water-wet. 3. For naturally oil-wet shale rocks, the wettability alteration effect is necessary to make spontaneous imbibition work, regardless of the IFT values. 4. The gravity effect is minor when compared to the capillary force in shale matrix, due to the extremely low permeability. 5. Both experimental and simulation results verified that surfactant with wettability alteration function while maintaining relatively high IFT is the best candidate to stimulate spontaneous imbibition in shale oil reservoir, then further maximize oil recoveries. Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. References [1] Aloulou F, Cook T. Tight oil expected to make up most of us oil production increase through 2040. U.S. Energy Information Administration; 2017. [Internet][cited June 2019]. Available from: https://www.eia.gov/todayinenergy/ detail.php?id=29932 . [2] Pang Y, Soliman MY, Deng H, Xie X. Experimental and analytical investigation of adsorption effects on shale gas transport in organic nanopores. Fuel 2017;199:272–88. [3] Sheng JJ. What type of surfactants should be used to enhance spontaneous imbibition in shale and tight reservoirs? J. Petrol. Sci. Eng. 2017;159:635–43. [4] Sharma S, Sheng JJ, Shen Z. A comparative experimental study of huff-n-puff gas injection and surfactant treatment in shale gas-condensate cores. Energy Fuels 2018;32(9):9121–31. [5] Li L, Sheng JJ, Su Y, Zhan S. Further investigation of effects of injection pressure and imbibition water on CO2 huff-n-puff performance in liquid-rich shale reservoirs. Energy Fuels 2018;32(5):5789–98. [6] Singh H. A critical review of water uptake by shales. J Nat Gas Sci Eng 2016;34:751–66. [7] Sheng JJ. Status of surfactant EOR technology. Petroleum 2015;1(2):97–105. [8] Phillips ZD, Halverson RJ, Strauss SR, Layman J, Green TW. A case study in the bakken formation: changes to hydraulic fracture stimulation treatments result in improved oil production and reduced treatment costs. In: Proceedings of the rocky mountain oil & gas technology symposium. Society of Petroleum Engineers; 2007. [9] Wang D, Butler R, Liu H, Ahmed S. Flow-rate behavior and imbibition in shale. SPE Reservo Evaluat Eng 2011;14(04):485–92. [10] Sheng JJ. Critical review of field eor projects in shale and tight reservoirs. J Petrol Sci Eng 2017;159:654–65. [11] Milter J, Austad T. Chemical flooding of oil reservoirs 6. evaluation of the mechanism for oil expulsion by spontaneous imbibition of brine with and without surfactant in water-wet, low-permeable, chalk material. Colloids Surf A: Physicoch Eng Aspects 1996;113(3):269–78. [12] Austad T, Matre B, Milter J, Saevareid A, Øyno L. 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 Surfaces A Physicoch Eng Aspects. 1998;137(1–3):117–29. [13] Spinler EA, Baldwin BA. Surfactant induced wettability alteration in porous media. Surfact Fund Appl Petrol Ind 20 0 0:159–202. [14] Chen HL, Lucas LR, Nogaret LA, Yang HD, Kenyon DE. Laboratory monitoring of surfactant imbibition using computerized tomography. In: Proceedings of the SPE international petroleum conference and exhibition in Mexico. Society of Petroleum Engineers; 20 0 0.

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