SPE 166281

EOR in Tight Oil Reservoirs through Wettability Alteration Prateek Kathel, SPE, and Kishore K. Mohanty, SPE, The University of Texas at Austin

Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, USA, 30 September–2 October 2013. 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 necessarily 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 prohibited. 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 In fractured reservoirs, the efficiency of water flood is governed by spontaneous imbibition of water into oil-containing matrix blocks. When the matrix is oil-wet or mixed-wet, little oil can be recovered by imbibition. The objective of this work is to identify chemicals that can be added to the injection water that can induce imbibition into an originally mixed-wet, tight, fractured sandstone reservoir. Several surfactants were evaluated for their aqueous stability at the reservoir temperature and salinity. Contact angles were measured on a clay-rich sandstone. Spontaneous imbibition tests were conducted on the reservoir rocks. It is shown that the use of dilute (0.1 wt %) surfactant solution can alter the wettability from oil-wet towards more water-wet condition on the mineral plates. Incremental oil recovery as high as 68% OOIP is obtained through spontaneous imbibition experiments performed on tight (~10 µD) oil-wet/mixed-wet sandstone reservoir cores. Parametric studies performed using numerical simulation show that the rate of oil recovery increases with increasing wettability alteration, increasing fracture density, and decreasing oil viscosity. Introduction Because the conventional oil resources are fast depleting, it becomes imperative to develop methods to harness unconventional oil resources like tight oil. The total tight oil reserves in North America are estimated to be more than 30 billion barrels contained in 24 oil reservoirs, among which only 14 reservoirs are under development (Forrest et al. 2011). A large amount of oil in tight formations is still unrecovered. Primary recovery remains as low as 5.0-10.0% of original oil in place, even after long horizontal wells have been drilled and massively fractured (Manrique et al. 2010). Oil recovery in tight oil-wet fractured sandstone reservoirs is a challenge. The recovery efficiency by waterflooding is very low if the formation is oil-wet and fractured (poor sweep) as no oil can be recovered through spontaneous imbibition and rock matrix remains saturated with oil. The oil recovery in fractured tight oil reservoirs depends critically on the wetting properties of the rock matrix. Large remaining oil after primary production in such reservoirs is a strong motivation to develop new secondary oil recovery methods. Many researchers have investigated recovering oil by fracturing tight formations (Miller et al., 2008, Buffington et al., 2010). There have been studies focused on CO2 injection in tight oil reservoirs (Arshad et al. 2009, Ren et al. 2011), but existence of fractures in the formation is detrimental to CO2 flooding (Arshad et al. 2009) leading to poor sweep and early breakthrough. This paper investigates an EOR technique based on wettability alteration of a mixed wet/oil wet fractured tight oil sandstone formation. Wettability is an important petrophysical property which impacts the rock fluid properties such as relative permeability, capillary pressure and distribution of fluid phases. Wettability depends on the brine, oil and mineral compositions as well as temperature (Anderson et al. 1986, Buckley, 2001, Gupta 2010). Wang and Gupta (1995) studied the influence of temperature and pressure on wettability of reservoir rocks. Pressure did not have a significant effect on contact angle; in contrast, temperature showed a significant effect on the wettability of crude-oil/brine/quartz systems. Using atomic force microscopy, Kumar et al. (2008) have shown that wettability of a rock is controlled by adsorption of asphaltenic components on the mineral surface. In fractured reservoirs, if the wettability is altered to water-wet, large amount of oil can be recovered through spontaneous imbibition. Wettability of a rock can be altered thermally (Al-Hadhrami et al. 2001) and chemically using surfactants, low salinity brine (Nasralla et al. 2013) as well as through selective ions (Zhang et al. 2006, RezaeiDoust et al. 2009, Gupta et al. 2011). The thermal process needs a very high temperature (~200 °C); even the low salinity brine process needs a high temperature (RezaeiDoust et al. 2010). Surfactants have the potential to alter wettability at low as well as high temperatures

2 SPE 166281

and they can also lower IFT at the oil-water interface. Past studies have identified cationic (Austad et al. 2003, Standnes and Austad 2000a,b), anionic (Seethepalli et al. 2008, Adibhatla et al. 2008, Gupta et al. 2010) and non-ionic surfactants (Xie et al. 2004, Gupta et al. 2010, Sharma et al. 2011) as wettability altering agents. Anionic surfactants make a good choice for use as wettability alteration agents for sandstones because they have a negative charge like the sandstone surface which results in low adsorption. Different mechanisms for wettability alteration have been postulated in the literature. Kumar et al. (2008) proposed micellar solubilization of adsorbed organic components by anionic surfactants. Standnes and Austad (2000) stated that wettability alteration takes place by ion pair formation between the cationic surfactant and adsorbed negatively charged carboxylates from oil on chalk surfaces. These ion pairs are dissolved in the oil phase and micelles. They further suggested that the imbibition mechanism depends on desorption of organic material from the rock surface and water imbibing in the porous media due to capillary forces. The desorption of organic molecules is related to diffusion of surfactant to the oil-water-rock boundary and is regarded as the rate determining process during initial stages of imbibition. The objective of this work is to find a wettability altering surfactant for a tight sandstone at the reservoir temperature (59 °C). The aqueous stability of surfactants was studied at several salinities at the reservoir temperature. Oil-water interfacial tension was measured at different salinities using a spinning drop tensiometer. Oil-surfactant solution contact angle was measured on a clayey mineral. The efficacy of the surfactants was tested by numerous spontaneous imbibition experiments at two different salinities. The scaling groups proposed in the literature for imbibition (Mattax et al. 1962, Ma et al. 1997) were tested with our experimental data. Numerical simulations are performed with an in-house simulator developed in previous studies (Adibhatla et al. 2005). Simulation results are validated against experimental data and various parameters are analyzed for their effect on rate of oil recovery during spontaneous imbibition. The methodology and results are described next. Methodology Materials Eight anionic surfactants (A1 to A8: alkyl ether sulphates and internal olefin sulphonates) and three nonionic surfactants (N1, N2 and N3) were tested in this study. No cationic surfactants were used in this study owing to the negative surface charge of sandstones. These surfactants are a combination of in-house developed surfactants and commercially available surfactants. The formation brine contained 132,000 ppm (mg/L) of dissolved salts. Detailed composition of brine is listed in Table 1. All the experiments were conducted with the reservoir dead oil. The contact angle tests were performed on Cristobalite mineral plates (a mineral with quartz and Kaolinite which was similar to the mineral composition of field cores). The spontaneous imbibition tests were performed on reservoir cores having permeability in the range of 10-100 µD. Actual undiluted field stock tank oil was used for the study. Oil viscosity is 2.7 cp at the reservoir temperature and specific gravity is 0.78. Oil was checked for contamination by measuring the oil-formation brine IFT which was around 21.8 dyne/cm (Hirasaki and Zhang, 2004).

Ion Ca2+ Mg2+ Na+ SO42- Cl- Total

Mass (mg/L) 2898 738 47654 250 81066 132606

Table 1: Formation brine composition Aqueous Stability Test Surfactant solutions were prepared in the formation brine and in half the salinity of the formation brine and kept at the reservoir temperature for at least two weeks. The aqueous solutions were observed for precipitation and suspension formation. A clear solution implies aqueous stability. Interfacial Tension Measurement (IFT) The IFT between the brine and oil phases was measured using a spinning drop tensiometer. Surfactant (0.1 wt %) was mixed with brine at the desired salinity and then equilibrated with oil. IFT measurement was made between the equilibrated aqueous and oleic phases. Contact Angle Measurement Surfactants which were aqueous stable at reservoir temperature were tested for wettability alteration. Cristobalite plates were polished (Figure 1) on a 600 mesh diamond polisher. They were first aged in the formation brine for a day and then aged in oil for around 7 days at 80 °C. They were then immersed in the surfactant solution and the change in contact angle was observed for at least 2 days.

SPE 166281 3

Figure 2: An imbibition cell with a core immersed in a surfactant solution

Spontaneous Imbibition Test Surfactants which altered the wettability on the Cristobalite plate were used for performing imbibition experiments on field cores. This serves as a final check for the efficacy of the surfactant. The field cores were first saturated with the formation brine and then the oil was injected. Cores were then aged in oil at 80 °C for about a month. Then the cores were placed in an imbibition cell (Figure 2) surrounded by various brines or surfactant solutions. As the brine imbibed into the core, oil was expelled and this oil floated to the neck of the cell where its volume was monitored. Ten imbibition experiments were conducted. The core properties and fluids used in different experiments are listed in Table 2.

Figure 1a: Mineral plate surface Figure 1b: Plate with oil drops, inside an optical cell filled with a surfactant

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Expt No. Porosity

k (mD)

Length (cm)

Dia. (cm) Surfactant Brine Soi

IFT (dynes/cm) NB

-1

Oil Recovery (OOIP)

1 0.089 0.03 5.522 2.514 No Surf. FB 0.51 21.8 3383.2 0.15

2 0.133 0.236 5.584 2.517 A2 FB 0.75 3.73 248.7 0.57

3 0.103 0.035 5.542 2.52 A2 FB 0.79 3.73 573.1 0.54

4 0.101 0.03 5.535 2.522 A2 FB 0.71 3.73 613.8 0.68

5 0.093 0.056 5.536 2.517 A2 FB/2 0.76 7.32 845.9 0.67

6 0.101 0.056 5.645 2.516 A2 FB/2 0.8 7.32 864.5 0.61

7 0.134 0.239 5.573 2.523 A6 FB 0.66 5.64 376.1 0.46

8 0.101 0.103 5.513 2.521 A6 FB 0.72 5.64 502.9 0.52

9 0.131 0.148 5.6 2.518 A6 FB/2 0.72 6.8 567.1 0.6

10 0.096 0.071 5.538 2.521 A5 FB/2 0.79 10.1 1052.7 0.42

Table 2: Core properties and spontaneous imbibition results for different experiments Results and Discussion Aqueous Stability Anionic surfactants. Figure 3 shows the aqueous stability results for anionic surfactants at the reservoir temperature. Ether sulphates (A1, A2, A5, A6) showed better aqueous stability compared to internal olefin sulphonates (A7, A8). Higher salinity diminishes aqueous stability of anionic surfactants. Only two out of the eight surfactants tested were aqueous stable at the formation brine salinity. The number of ethoxy groups in the surfactant plays a major role in aqueous stability at higher salinities. It was observed that more the number of ethoxy groups in the surfactant, the higher was the aqueous stability.

Figure 3: Aqueous stability results for anionic surfactants Nonionic surfactants. The non-ionic surfactants used during this study are of the form R-EOx where R is a hydrocarbon attached to a chain containing x ethoxy groups. The three surfactants tested contained the same R but different (x) number of ethoxy groups. For all the three surfactants, the cloud point was higher than the reservoir temperature and they resulted in aqueous stable solutions even at high salinities as shown in Figure 4.

0

6.6

13.2

0 1 2 3 4 5 6 7 8

Sal

init

y (w

t%)

Anionic Surfactant

Stable

Unstable

(FB)

(FB/2)

1: A12: A23: A34: A45: A56: A67: A78: A8

SPE 166281 5

Figure 4: Aqueous stability results for non-ionic surfactants Interfacial Tension Figure 5 shows the IFT between the aqueous and the oleic phases as a function of salinity in the crude oil-brine-surfactant systems. For both of these anionic surfactants IFT decreased with increase in salinity. Increase in salinity leads to more competition between surfactant and salts for solubilization in water, as a result more surfactant monomers tend to move towards the interface. More monomers at the interface result in lowering of the interfacial tension with the increase in salinity.

Figure 5: IFT values for surfactant A2 and A6 with varying salinity.

Contact Angle Figure 6 shows pictures of oil droplets on Cristobalite plates submerged in surfactant/brine solution in an optical cell and Table 3 gives the contact angle values. The nonionic surfactants N1, N2 and N3 altered the contact angle, but not to the extent required. Also it was observed that more the number of ethoxy groups (most in N3, least in N1), more was the change in contact angle. But no non-ionic surfactant was able to make the Cristobalite plate water-wet (θ < 80°). Among the six combinations of anionic surfactants which were aqueous stable, five altered the wettability from oil-wet to water-wet. Two surfactants (A2 and A6) altered the wettability at both the salinities that we tested (formation brine and half the formation brine). The average contact angles observed were nearly the same at both the salinities. These surfactants were then studied in detail with regard to their interfacial tension variation with salinity and also reproducibility of spontaneous imbibition experiments.

0

6.6

13.2

0 1 2 3

Sal

init

y (w

t%)

Non Ionic Surfactant

Stable

Unstable

(FB)

(FB/2) 1: N12: N23: N3

3

5

7

9

11

13

15

0 5 10 15

IFT (dynes/cm)

Salinity (wt %)

A2

A6

6 SPE 166281

Figure 6: Oil droplets on Cristobalite plates submerged in surfactant/brine solutions

FB 0.1 wt% A2 in FB/2

0.1 wt % A1 in FB/2 0.1 wt% A6 in FB/2

0.1 wt% A6 in FB

0.1 wt% A2 in FB 0.1 wt% N1 in FB

0.1 wt% N2 in FB 0.1 wt% N3 in FB

0.1 wt% A5 in FB/2

SPE 166281 7

Surfactant Brine Wt % Average Contact angle (°) - FB - 150

A1 FB/2 0.1 130 A2 FB/2 0.1 72 A5 FB/2 0.1 74 A6 FB/2 0.1 70 A2 FB 0.1 74 A6 FB 0.1 74 N1 FB 0.1 145 N2 FB 0.1 110 N3 FB 0.1 90

Table 3: Contact angle results Spontaneous Imbibition Imbibition experiments were performed with the surfactants which altered the wettability of Cristobalite plates. Figure 7 shows an oil-wet reservoir core. A water drop placed on top of the aged core does not imbibe, confirming the oil-wetness of the core.

Figure 7: A water drop on top of an aged core showing its oil wettability

Table 2 lists the results of the imbibition experiments. The oil recovery due to spontaneous imbibition is listed for each experiment when an oil-saturated core plug is surrounded by different brines. Experiment 1 is for the formation brine. The oil recovery is 15%, which suggests that the matrix is mixed-wet with a dominant oil-wet fraction. Three imbibition experiments (Experiment 2-4) were performed with surfactant A2 in the formation brine (FB). Experiments 2 and 3 gave similar final oil recovery values while Experiment 4 gave a significantly higher value. However, in these three cases with surfactant A2 the recovery was high (54-68%) implying that the surfactant A2 is effective as a wettability altering agent. The difference in final oil recovery can be attributed to heterogeneities in the core since these experiments were performed on different core plugs from the same reservoir. Similarly for Experiments 5 and 6 for surfactant A2 in half the formation brine salinity (FB/2), the oil recovery by spontaneous imbibition is also high (61-67%). Experiments 7 and 8 are for surfactant A6 in formation brine which give oil recoveries of 46-52% OOIP. The lowest recovery (42%) was obtained for surfactant A5 (Experiment 10) in half the formation brine salinity. The oil recovery by spontaneous imbibition is significant (42-68% OOIP) for surfactants A2, A5 and A6.

The macroscopic inverse bond number is defined as the ratio of capillary to gravity forces, i.e.,

1B

kNgH

(1)

where σ is the interfacial tension, φ is porosity, k is permeability, ∆ρ is the density difference, and H is the height of the core. It is listed for the imbibition experiments in Table 2. High values of inverse bond number were obtained because of low permeability of the cores, which implies that the capillary force exceeds the gravity force.

8 SPE 166281

Figure 8: Oil droplets at the outer surface of the cylindrical core plug during spontaneous imbibition experiment in surfactant solution.

Figure 8 shows one of the cores placed in a surfactant solution. Oil droplets come out of the core on all sides as brine imbibes. This suggests that the dominant imbibition mechanism is the counter current imbibition due to the capillary pressure gradient caused by the wettability alteration. High values of inverse bond number imply high capillary forces compared to buoyancy forces. If the wettability is altered, these capillary forces aid in the imbibition of brine through the periphery of the core (Gupta et al. 2008).

Figure 9 shows the oil recovery as a function of time for the ten spontaneous imbibition experiments performed. The experiment where no surfactant is used shows the lowest recovery (15 %). It takes 9 days before any oil is collected at the neck of the imbibition cell. In this period the oil drops appeared on the periphery of the core, but they did not detach and collect in the neck. For the surfactant solutions, 80% of the finally recovered oil is recovered in the first 20 days; the rate of recovery gradually decreases as the saturation of aqueous phase increases in the core. The initial rate of oil recovery varied significantly between the experiments.

Figure 9: Oil recovery from spontaneous imbibition

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0 10 20 30 40 50 60

Oil

Rec

over

y (

frac

. OO

IP)

Time (Days)

Expt. 3: A2, FB

Expt. 2: A2, FB

Expt. 4: A2, FB

Expt. 8: A6, FB

Expt. 7: A6, FB

Expt. 1: ‐, FB

Expt. 6: A2, FB/2

Expt. 10: A5, FB/2

Expt. 5: A2, FB/2

Expt. 9: A6, FB/2

SPE 166281 9

Some of the cores had almost the same initial oil saturation and imbibition was performed using the same surfactant, but at different salinities. As a result of varying salinity the interfacial tension between oil/water is varied. Figures 10 and 11 show the oil recovery curves for imbibition experiments performed with the same surfactant at different salinities. It was observed that the rate of recovery was higher for the higher IFT cases. Also, ultimate oil recovery was higher for the higher IFT case in both the sets.

Figure 10: Recovery rate comparison for surfactant A2

Figure 11: Recovery rate comparison for surfactant A6 Scaling Groups Scaling groups are a means to analyze the spontaneous imbibition data as well as to predict oil recovery and recovery rates at the field-scale. Several studies (Mattax and Kyte 1962, Ma et al. 1997) have identified scaling groups for different types of porous media and Schmidt et al. (2012) attempted to find a universal scaling group for water-wet systems which can give good correlation for all conditions. Mattax and Kyte (1962) scaling equation is given by:

2

1D

w

kt t

L

(2)

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0 10 20 30 40 50 60

Oil

Rec

over

y (O

OIP

)

Time (Days)

Expt. 2: A2, FB Expt. 5: A2, FB/2

7.32 dyne/cm

3.73 dyne/cm

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0 10 20 30 40 50 60

Oil

Rec

over

y (O

OIP

)

Time (Days)

Expt. 8: A6, FB Expt. 9: A6, FB/2

10 SPE 166281

Ma et al. 1997 scaling equation is given by:

2

1D

co w

kt t

L

, 2 22 2

c

LdL

d L

(3)

where Dt is dimensionless time, t is the actual time of imbibition, o is oil viscosity, w is water viscosity, cL is the

characteristic length. Our experimental data was plotted using Mattax and Kyte scaling equation (Eq. 2) as well as the scaling group proposed by Ma et al. (Eq. 3). Figures 12 and 13 show that all the data do not fall on one curve, but the correlation was slightly better for Ma et al. scaling group as compared to Mattax and Kyte (1962). Both the scaling equations are for strongly water-wet porous media and are insufficient to explain the dynamics of changing wettability from oil-wet to water-wet.

Figure 12: Imbibition data plotted with Mattax and Kyte dimensionless time.

Figure 13: Imbibition data plotted with dimensionless time given by Ma et al. (1997)

0

0.2

0.4

0.6

0.8

1

0.1 1 10 100

Nor

m. O

il R

ecov

ery

td

Expt. 2: A2, FB

Expt. 4: A2, FB

Expt. 7: A6, FB

Expt. 8: A6, FB

Expt. 3: A2, FB

Expt. 6: A2, FB/2

Expt. 10: A5, FB/2

Expt. 5: A2, FB/2

Expt. 9: A6, FB/2

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0.0001 0.001 0.01 0.1 1

Nor

m. O

il R

ecov

ery

td

Expt. 2: A2, FB

Expt. 4: A2, FB

Expt. 7: A6, FB

Expt 3: A2, FB

Expt 8: A6, FB

Expt. 6: A2, FB/2

Expt. 10: A5, FB/2

Expt. 5: A2, FB/2

Expt. 9: A6, FB/2

SPE 166281 11

Simulation A mechanistic simulator developed in previous studies (Adibhatla et al. 2005) was used to perform parametric analysis after successful lab-scale validation. The simulator uses a 3D finite volume, two-phase, four-component implicit numerical scheme. There is no third phase formation observed during oil/brine/surfactant phase behavior experiments performed for our system; hence the system is essentially two-phase. The numerical model takes into account surfactant convection/diffusion, consequent IFT and contact angle changes. The injected surfactant moves into the matrix because of flow caused by wettability alteration and IFT reduction. The critical input parameters include capillary pressure (PC) and relative permeability curves (krj) as well as their variation with surfactant concentration. Capillary pressure is assumed to depend on saturation through a power-law model.

( ) ( ) cnC DW CA CB DWP S P P S (4)

In Eq. 4, CAP and CBP determine the endpoints of the capillary pressure curve, cn is the exponential parameter and DWS is the

dimensionless water saturation defined by

1j jr

Djwr or

S SS

S S

(5)

The capillary pressure depends on interfacial tension ( ) and contact angle ( ) according to

00 0

cos( )

cosC C DWP P S

. (6)

The subscript ‘0’ on capillary pressure, interfacial tension and contact angle indicates values for an initial oil-wet system. Relative permeability curves are described by a modified Brooks-Corey model, i.e.,

0 ( ) jnrj rj Djk k S (7)

where 0rjk is the endpoint relative permeability of phase j and jn is the exponential parameter for phase j. The endpoint

permeabilities and exponents vary with contact angle as follows:

00 0 0 0, , ,

0 0

cos cos( )

cos( ) cosj

rj r wet r nw r wetk k k k

(8)

and

0

0 0

cos cos( )

cos( ) cosj

j wet nw wetn n n n

. (9)

j is the contact angle measured through phase j, 0,r wetk corresponds to the wetting phase endpoint relative permeability and

0,r nwk corresponds to the non-wetting phase endpoint relative permeability. As the IFT is not reduced to an ultra-low value,

residual saturations are assumed constant. IFT and contact angle variations with surfactant concentration are modeled as polynomial and linear functions, respectively, with endpoint parameters obtained from experimental data. The values of different parameters used in the simulation are provided in Table 4.

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Parameter Value

orS 0.25 0,r wetk 0.2

,

0r nwk 0.9

wetn 4.5

nwn 2.25

0 (rad) 0

CAP (Pa) 10342

CBP (Pa) 30000000

cn 1.3

Table 4: Values of parameters used in simulation

The reliability of the simulator is established by comparing the core scale simulation results with the results from laboratory imbibition experiment 2 (Figure 14). Through the simulations, we have analyzed the effect of three parameters: extent of wettability alteration, fracture spacing and oil viscosity on amount and rate of oil recovery.

Figure 14: Comparison of experimental and simulation results.

Figure 14 shows the comparison between numerical simulation and experiment 2. A good match is obtained between simulated oil recovery and experimental data. There is a slight mismatch during the early period which can be due to the error in measuring recovered volumes. When the oil-wet core is immersed in an imbibition cell and surrounded by brine/surfactant solution, the entry capillary pressure opposes and exceeds the gravitational force for water influx from bottom; hence brine does not imbibe immediately. As surfactant diffuses into the core, IFT and wettability of the core change. In our system the IFT is not lowered to ultra-low IFT values, hence even after alteration of wettability which changes capillary pressure from negative to positive, capillary pressure remains high and leads to significant counter-current imbibition. As the wettability is altered towards water-wet, the relative permeability of the oil phase increases and enhances oil recovery. The effect of wettability alteration on oil recovery was studied by changing the contact angle from initial value of 150° to final values of 90° (intermediate-wet), 88° (slightly water-wet), 75° (water-wet) and 60° (more water-wet) . All other parameters including IFT were same in all the cases. It was observed that by increasing the extent of wettability alteration, rate of oil recovery increased as shown in Figure 15. The dominant recovery process is capillary pressure driven counter current imbibition hence even a slight change towards water wet (88°) leads to high recovery rate compared to the

SPE 166281 13

intermediate wet case. As the contact angle decreases, the capillary pressure increases and the oil relative permeability increases while the water relative permeability decreases. These factors increase the imbibition rate.

Figure 15: Effect of extent of wettability alteration on oil recovery. Figure 16 shows the simulation results obtained by varying the fracture spacing: 1x represents the original diameter of the core, 2x is for the core of twice the original diameter and so on. As the fracture spacing increases, the distance to transport the fluids increases and the oil recovery rate (in terms of OOIP) decreases. Figure 17 shows the effect on oil recovery by changing oil viscosity. Increase in viscosity of oil leads to low oil recovery rates. Hence imbibition driven recovery processes are more suitable for light oils. An increase in oil viscosity leads to reduced oil mobility which can be compensated by increased extent of wettability alteration and reduced fracture spacing to maintain desirable oil recovery rate.

Figure 16: Effect of fracture spacing on oil recovery.

14 SPE 166281

Figure 17: Effect of oil viscosity on oil recovery.

Conclusions • Anionic surfactants A2, A5, and A6 alter the wettability of clay-rich sandstones. • High oil recovery (42-68 %OOIP) is observed during imbibition experiments in very low permeability sandstones. • The main recovery mechanism is capillary pressure gradient-driven counter-current imbibition due to wettability

alteration in these experiments. • The rate of oil recovery increases with increasing IFT. • Parametric studies performed using numerical simulation show that the rate of oil recovery increases with increasing

wettability alteration, increasing fracture density, and decreasing oil viscosity.

Acknowledgements We are thankful to the sponsors of Chemical EOR Industrial Affiliates Project at The University of Texas at Austin for partial funding of this work. References Adibhatla, B., and Mohanty, K. 2008. Oil Recovery from Fractured Carbonates by Surfactant-Aided Gravity Drainage: Laboratory

Experiments and Mechanistic Simulations. SPE Reservoir Evaluation & Engineering 11 (1): 119-130. Adibhatla, B., Sun, X., and Mohanty, K. 2005. Numerical Studies of Oil Production from Initially Oil-Wet Fracture Blocks by Surfactant

Brine Imbibition. Paper SPE 97687 presented at the SPE International Improved Oil Recovery Conference in Asia Pacific, Kuala Lumpur, 5-6 December.

Al-Hadhrami, H., and Blunt, M. 2001. Thermally Induced Wettability Alteration to Improve Oil Recovery in Fractured Reservoirs. SPE Reservoir Evaluation & Engineering 4 (3): 179-186.

Anderson, W. 1986. Wettability Literature Survey-Part 1: Rock/Oil/Brine Interactions and the Effects of Core Handling on Wettability. Journal of Petroleum Technology 38 (10): 1125-1144.

Arshad, A., Al-Majed, A., Menouar, H., Muhammadain, A., and Mtawaa, B. 2009. Carbon Dioxide (CO2) Miscible Flooding in Tight Oil Reservoirs: A Case Study. Paper SPE 127616 presented at the Kuwait International Petroleum Conference and Exhibition, Kuwait City, 14-16 December.

Austad, T., and Standnes, D. C. 2003. Spontaneous Imbibition of Water into Oil-Wet Carbonates. Journal of Petroleum Science and Engineering 39 (3): 363-376.

Buckley, J. S. 2001. Effective Wettability of Minerals Exposed to Crude Oil. Current Opinion in Colloid & Interface Science 6 (3): 191-196.

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Buffington, N., Kellner, J., King, J., David, B., Demarchos, A., and Shepard, L. 2010. "New Technology in the Bakken Play Increases the Number of Stages in Packer/Sleeve Completions." Paper SPE 133540 presented at the SPE Western Regional Meeting, Anaheim, 27-29 May.

Forrest, J., Birn, K., Brink, S., Comb, T.J., Cuthbert, B., Dunbar, R.B., Harju, J.A., Isaace, E., Jones, F., Khanna, P., Snarr, D.G., Sorensen, J.A., Wall, T.J., and Whitney, D., 2011. Working Document of the NPC North American Resource Development Study, Paper #1-6, Unconventional Oil, Tight Oil.

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