Article pubs.acs.org/EF
Wettability Alteration in a Tight Oil Reservoir P. Kathel and K. K. Mohanty* Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, Texas 78712, United States ABSTRACT: In fractured reservoirs, the efficiency of water flood is governed by spontaneous imbibition of water into oilcontaining 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 %) anionic surfactant solution with a large number of ethoxy groups can alter the wettability from oil-wet toward more water-wet conditions on the mineral plates. Incremental oil recovery as high as 68% original oil in place is obtained through spontaneous imbibition experiments performed on tight (∼10 μD) oil-wet/mixed-wet sandstone reservoir cores. A three-dimensional fine grid mechanistic simulator was used to perform lab-scale validation and parametric analysis. Parametric studies show that the rate of oil recovery increases with increasing wettability alteration, increasing fracture density, and decreasing oil viscosity.
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thermally11 and chemically using surfactants, low-salinity brine,12 and selective ions.13−15 Wettability alteration because of thermal processes requires a very high temperature (∼200 °C). The low-salinity brine process is also temperaturedependent,16 and a change in wettability is induced in carbonates at temperatures higher than 90 °C. Surfactants have the potential to alter wettability at low as well as high temperatures, and they can also lower interfacial tension (IFT) at the oil−water interface. Past studies have identified cationic,17−19 anionic,20−22 and non-ionic8,23 surfactants 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.10 proposed micellar solubilization of adsorbed organic components by anionic surfactants. Standnes and Austad19 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 upon desorption of organic material from the rock surface and water imbibing in the porous media because of capillary forces. Desorption of organic molecules is related to diffusion of the 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 IFT was measured at different salinities using a spinning drop
INTRODUCTION The soaring world energy demand coupled with declining conventional oil production prompts toward an increased emphasis on harnessing unconventional resources, such as tight oil. Primary recovery is between 5 and 10% of the original oil in place (OOIP) in tight oil reservoirs, even after long horizontal wells have been drilled and massively fractured.1 The oil recovery by waterflooding in fractured tight oil reservoirs critically depends upon the wetting properties of the rock matrix. Waterflooding is not very effective if the formation is oil-wet and fractured (poor sweep), because no oil can be recovered through spontaneous imbibition and the rock matrix remains saturated with oil. 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.2,3 There have been studies focused on CO2 injection in tight oil reservoirs,4,5 but existence of fractures in the formation is detrimental to CO2 flooding,4 leading to poor sweep and early breakthrough. This paper investigates an enhanced oil recovery (EOR) technique based on wettability alteration of a mixedwet/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 upon the brine, oil, and mineral compositions as well as the temperature.6−8 Wang and Gupta9 studied the influence of the temperature and pressure on wettability of reservoir rocks. Pressure did not have a significant effect on the contact angle; in contrast, the temperature showed a significant effect on the wettability of crude oil/brine/quartz systems. Using atomic force microscopy, Kumar et al.10 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 waterwet, a large amount of oil can be recovered through spontaneous imbibition. Wettability of a rock can be altered © 2013 American Chemical Society
Received: July 5, 2013 Revised: September 17, 2013 Published: September 17, 2013 6460
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Contact Angle Measurement. Surfactants that were aqueous stable at the reservoir temperature were tested for wettability alteration. Cristobalite plates were polished (Figure 1) on a 600-
tensiometer. The oil−surfactant solution contact angle was measured on a clay-rich 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 imbibition24,25 were tested with our experimental data. Numerical simulations were performed with an in-house simulator developed in previous studies.26 Simulation results were validated against experimental data, and various parameters were analyzed for their effect on the rate of oil recovery during spontaneous imbibition. The methodology and results are described next.
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METHODOLOGY
Materials. Eight anionic surfactants (A1−A8, alkyl ether sulfates and internal olefin sulfonates) and three non-ionic surfactants (N1, N2, and N3) were tested in this study. Their chemical formulas are listed in Table 1. No cationic surfactants were used in this study, owing
Table 1. List of Surfactants Tested number
surfactant name Anionic Surfactants C13-(EO)6-sulfate C13-(EO)27-sulfate C13-(PO)7-sulfate C(16−17)-(PO)7-sulfate C24-(PO)25-(EO)46-sulfate C20-(PO)7-(EO)30-sulfate 15−18 internal olefin sulfonate 20−24 internal olefin sulfonate Non-ionic Surfactants 15-S-20 15-S-30 15-S-40
A1 A2 A3 A4 A5 A6 A7 A8 N1 N2 N3
Figure 1. Plate with oil drops, inside an optical cell filled with a surfactant solution.
to the negative surface charge of sandstones. Surfactants A1−A6 were developed in-house. Surfactants A7 and A8 were from Stepan, and N1−N3 were from Dow Chemicals. The formation brine contained 132 000 ppm (mg/L) of dissolved salts. Detailed composition of brine is listed in Table 2. All of the
mesh diamond polisher. They were first aged in the formation brine for 1 day and then aged in oil for around 7 days at 80 °C. They were then immersed in the surfactant solution, and the contact angles were observed for at least 2 days. Around 5−7 oil droplets were chosen on the polished part of the plate (which have well-characterized angles obtained upon zooming the high-resolution contact angle pictures). An average value is obtained from these values. Spontaneous Imbibition Test. Surfactants that 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 1 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. A total of 10 imbibition experiments were conducted. The core properties and fluids used in different experiments are listed in Table 3.
Table 2. Formation Brine Composition ion
Ca2+
Mg2+
Na+
SO42−
Cl−
total
mass (mg/L)
2898
738
47654
250
81066
132606
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 dyn/cm.27 Aqueous Stability Test. Surfactant solutions were prepared in the formation brine and in half of the salinity of the formation brine and kept at the reservoir temperature for at least 2 weeks. The aqueous solutions were observed for precipitation and suspension formation. A clear solution implies aqueous stability. IFT Measurement. 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. The IFT measurement was made between the equilibrated aqueous and oleic phases.
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RESULTS AND DISCUSSION There are many factors that guide surfactant selection. They are temperature, salinity, and hardness of formation and injection brines, surface charge on the reservoir rock, and known results for similar conditions. Anionic and non-ionic surfactants were chosen because they adsorb less on the sandstone surface (which has negative ζ potential) than cationic surfactants. The reservoir temperature was relatively low; thus, sulfates and 6461
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Figure 3. Aqueous stability results for anionic surfactants.
number of ethoxy groups in the surfactant, the higher the aqueous stability. 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) numbers of ethoxy groups. For all 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.
Figure 2. Imbibition cell with a core immersed in a surfactant solution. Figure 4. Aqueous stability results for non-ionic surfactants.
ethoxy groups were selected as the hydrophilic groups. The salinity and hardness were high, which also led to surfactants with a large number of ethoxy groups. Aqueous Stability. Figure 3 shows the aqueous stability results for anionic surfactants at the reservoir temperature. Ether sulfates (A1, A2, A5, and A6) showed better aqueous stability compared to internal olefin sulfonates (A7 and A8). Higher salinity diminishes the aqueous stability of anionic surfactants. Only two 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 the greater the
IFT. Figure 5 shows the IFT between the aqueous and oleic phases as a function of the salinity in the crude oil−brine− surfactant systems. For both of these anionic surfactants, IFT decreased with an increase in salinity. The phase behavior was Winsor Type II, where the surfactant stays mostly in the aqueous phase. An increase in salinity leads to more competition between the surfactant and salts for solubilization in water, and as a result, more surfactant molecules tend to move toward the interface. More surfactant at the interface results in lowering of the IFT with the increase in the salinity.
Table 3. Core Properties and Spontaneous Imbibition Results for Different Experiments experiment number
porosity
k (mD)
length (cm)
diameter (cm)
surfactant
brine
Soi
IFT (dyn/cm)
N−1 B
oil recovery (OOIP)
1 2 3 4 5 6 7 8 9 10
0.089 0.133 0.103 0.101 0.093 0.101 0.134 0.101 0.131 0.096
0.03 0.236 0.035 0.03 0.056 0.056 0.239 0.103 0.148 0.071
5.522 5.584 5.542 5.535 5.536 5.645 5.573 5.513 5.6 5.538
2.514 2.517 2.52 2.522 2.517 2.516 2.523 2.521 2.518 2.521
no surfactant A2 A2 A2 A2 A2 A6 A6 A6 A5
FB FB FB FB FB/2 FB/2 FB FB FB/2 FB/2
0.51 0.75 0.79 0.71 0.76 0.8 0.66 0.72 0.72 0.79
21.8 3.73 3.73 3.73 7.32 7.32 5.64 5.64 6.8 10.1
3383.2 248.7 573.1 613.8 845.9 864.5 376.1 502.9 567.1 1052.7
0.15 0.57 0.54 0.68 0.67 0.61 0.46 0.52 0.6 0.42
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optical cell, and Table 4 gives the average contact angle values. The standard deviation was about 5°. The non-ionic surfactants Table 4. Contact Angle Results
Figure 5. IFT values for surfactants 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
surfactant
brine
weight percent
average contact angle (deg)
A1 A2 A5 A6 A2 A6 N1 N2 N3
FB FB/2 FB/2 FB/2 FB/2 FB FB FB FB FB
0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
150 130 72 74 70 74 74 145 110 90
Figure 6. Oil droplets on plates submerged in surfactant/brine solutions. 6463
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N1, N2, and N3 altered the contact angle but not to the extent required. Also, it was observed that the greater the number of ethoxy groups (most in N3 and least in N1), the greater the change in the contact angle. However, 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 salinities. These surfactants were then studied in detail with regard to their IFT variation with the salinity and also reproducibility of spontaneous imbibition experiments. Spontaneous Imbibition. Imbibition experiments were performed with the surfactants that 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.
NB−1
σ =
φ k
ΔρgH
(1)
where σ is the IFT, φ is the porosity, k is the permeability, Δρ is the density difference, and H is the height of the core. It is listed for the imbibition experiments in Table 3. 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. Figure 8 shows one of the cores placed in a surfactant solution. Oil droplets come out of the core on all sides as brine
Figure 8. Oil droplets at the outer surface of the cylindrical core plug during a spontaneous imbibition experiment in surfactant solution. Figure 7. Water drop on top of an aged core, showing its oil wettability.
imbibes. This suggests that the dominant imbibition mechanism is the counter-current imbibition because of 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. Figure 9 shows the oil recovery as a function of time for the 10 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
Table 3 lists the results of the imbibition experiments. The oil recovery because of 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 the final oil recovery can be attributed to heterogeneities in the core because 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.
Figure 9. Oil recovery from spontaneous imbibition. 6464
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The Ma et al.25 scaling equation is given by
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 the aqueous phase increases in the core. The initial rate of oil recovery varied significantly between the experiments. 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 IFT between oil/water is varied. Figures 10 and 11 show the oil
tD = t
k ϕ
σ 1 , μo μw Lc 2
Lc =
Ld 2
2 d + 2L2
(3)
where tD is dimensionless time, t is the actual time of imbibition, μo is the oil viscosity, μw is the water viscosity, and Lc is the characteristic length. Our experimental data were plotted using the Mattax and Kyte24 scaling equation (Figure 12), as well as the scaling group proposed by Ma et al.25 (Figure
Figure 12. Imbibition data plotted with Mattax and Kyte dimensionless time. Figure 10. Recovery rate comparison for surfactant A2.
Figure 13. Imbibition data plotted with dimensionless time given by Ma et al.
Figure 11. Recovery rate comparison for surfactant A6.
13). The correlation was slightly better for the Ma et al.25 scaling group compared to Mattax and Kyte.24 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. Simulation. A mechanistic simulator developed in previous studies27 was used to perform parametric analysis after successful lab-scale validation. The simulator uses a threedimensional (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.
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 sets. Scaling Groups. Scaling groups provide a means to analyze the spontaneous imbibition data as well as to predict oil recovery and recovery rates at the field scale. Several studies24,25 have identified scaling groups for different types of porous media. Schmid and Geiger28 attempted to find a universal scaling group for water-wet systems, which can give a good correlation for all conditions. Schechter et al.29 have conducted experiments to validate these scaling groups with varying IFT but constant wettability. The Mattax and Kyte24 scaling equation is given by tD = t
k σ 1 φ μw L2
(2) 6465
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The critical input parameters include capillary pressure (PC) and relative permeability curves (krj) as well as their variation with the surfactant concentration. Capillary pressure is assumed to depend upon saturation through a power-law model. PC(SDW ) = PCA + PCB(SDW )nc
(4)
In eq 4, PCA and PCB determine the end points of the capillary pressure curve, nc is the exponential parameter, and SDW is the dimensionless water saturation defined by SDj =
Sj − Sj r 1 − Swr − Sor
(5)
The capillary pressure depends upon the IFT (σ) and contact angle (θ) according to PC = PC0(SDW )
σ cos θ σ0 cos θ0
Figure 14. Comparison of experimental and simulation results.
(6)
The subscript “0” on capillary pressure, IFT, and contact angle indicates values for an initial oil-wet system. Relative permeability curves are described by a modified Brooks− Corey model, i.e.
k rj = k r0j(SDj)nj
we have analyzed the effect of three parameters, extent of wettability alteration, fracture spacing, and oil viscosity, on the amount and rate of oil recovery. 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 the bottom; hence, brine does not imbibe immediately. As the surfactant diffuses into the core, the IFT and wettability of the core change. In our system, the IFT is not lowered to ultralow 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 toward 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 an 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 the same in all of the cases. It was observed that, by increasing the extent of wettability alteration, the 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 toward water-wet (88°) leads to a high recovery rate compared to the 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 16 shows the simulation results obtained by varying the fracture spacing: 1× represents the original diameter of the core; 2× is for the core of twice the original diameter; etc. 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. An increase in the viscosity of oil leads to low oil recovery rates. Hence, imbibition-driven recovery processes are more suitable for light oils. An increase in oil
(7)
k0rj
where is the end-point relative permeability of phase j and nj is the exponential parameter for phase j. The end-point permeabilities and exponents vary with the contact angle as follows: 0 k r0j = k r,wet +
cos θj − cos θ0 cos(π − θ0) − cos θ0
0 0 (k r,nw ) − k r,wet
(8)
and nj = n wet +
cos θj − cos θ0 cos(π − θ0) − cos θ0
(nnw − n wet)
(9)
where θj is the contact angle measured through phase j, k0r,wet corresponds to the wetting phase end-point relative permeability, and k0r,nw corresponds to the non-wetting phase endpoint relative permeability. Because the IFT is not reduced to an ultralow value, residual saturations are assumed constant. IFT and contact angle variations with the surfactant concentration are modeled as polynomial and linear functions, respectively, with end-point parameters obtained from experimental data. The values of different parameters used in the simulation are provided in Table 5. The reliability of the simulator is established by comparing the core-scale simulation results to the results from laboratory imbibition experiment 2 (Figure 14). Through the simulations, Table 5. Values of Parameters Used in the Simulation parameter
value
Sor k0r,wet k0r,nw nwet nnw θ0 (rad) PCA (Pa) PCB (Pa) nc
0.25 0.2 0.9 4.5 2.25 0 10342 30000000 1.3 6466
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fracture spacing of 1 m or smaller to be fast enough in the field scale.
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CONCLUSION Anionic surfactants with a large number (>20) of ethoxy groups 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 the capillary-pressure-gradient-driven countercurrent imbibition because of 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. This study suggests that wettability alteration is an effective method in producing oil from tight media if the fracture spacing is 1 m or smaller.
Figure 15. Effect of the extent of wettability alteration on oil recovery.
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AUTHOR INFORMATION
Corresponding Author
*Telephone: 512-471-3077. Fax: 512-471-9605. E-mail:
[email protected]. Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS We are thankful to the sponsors of the Gas EOR Industrial Affiliates Project at The University of Texas at Austin for partial funding of this work.
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Figure 16. Effect of fracture spacing on oil recovery.
REFERENCES
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Figure 17. Effect of oil viscosity on oil recovery.
viscosity leads to reduced oil mobility, which can be compensated by an increased extent of wettability alteration and a reduced fracture spacing to maintain a desirable oil recovery rate. In reservoirs, fractures occur at many length scales from centimeters to several meters. The fractures may or may not be all connected. From eq 3 and Figure 16, it is clear that, as the fracture spacing increases, the time for equivalent oil recovery increases as Lc2. If the fracture spacing is 1 m, it would take about 30 years to recover about 30% OOIP based on Figure 14. Thus, the wettability alteration process is slow. It would require 6467
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dx.doi.org/10.1021/ef4012752 | Energy Fuels 2013, 27, 6460−6468
