Wettability Altering Secondary Oil Recovery in Carbonate Rocks

Carbonate rocks tend to be oil-wet, leading to lower oil relative permeability and lower oil recovery in the life of a waterflood, which is about 3 po...
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Wettability Altering Secondary Oil Recovery in Carbonate Rocks K. Mohan,† R. Gupta,† and K. K. Mohanty*,‡ †

Department of Chemical and Biomolecular Engineering, University of Houston, 4200 Calhoun Road, Houston, Texas 77204, United States ‡ Department of Petroleum and Geosystems Engineering, University of Texas, 1 University Station C0300, Austin, Texas 78712, United States ABSTRACT: Carbonate rocks tend to be oil-wet, leading to lower oil relative permeability and lower oil recovery in the life of a waterflood, which is about 3 pore volume (PV) injection. The goal of this work is to improve oil recovery during secondary waterflood by wettability alteration because of a surfactant addition. The effect of the surfactant is studied by contact angle measurement, spontaneous imbibition, and secondary water/surfactant flood in reservoir cores. The contact angle changes from oilwet to intermediate-wet in the presence of 0.2 wt % of a surfactant. Brine (without surfactant) does not imbibe into the core spontaneously, but surfactant brine imbibes to the extent of 20% of the oil in place. Secondary waterflooding recovers about 62% of the oil in about 3 PV injection and 80% in about 16 PV. Secondary surfactant flooding recovers about 85% in about 3 PV and about 90% in 4 PV. Injection of 1 PV of surfactant solution followed by waterflood also recovers about 83% of the oil in a total injection of 3 PV. This increase in oil recovery from 62 to 85% by wettability alteration is very significant and needs to be evaluated at the field scale.

1. INTRODUCTION Almost 60% of the world’s remaining oil lies within carbonate reservoirs.1,2 Carbonate reservoirs can be fractured or nonfractured. Most carbonate reservoirs tend to be oil-wet or mixedwet.3 5 Current recovery techniques, such as waterflooding, recover only 40 50% of the original oil in place (OOIP) in nonfractured carbonates; the recovery is much smaller in fractured oil-wet carbonate reservoirs. Considering the large amount of oil in place, the poor waterflood recovery, and the increasing world energy demand, it is very important to improve oil recovery from carbonate reservoirs. In this work, we are interested in improving oil recovery from a low-permeability (2 5 md) nonfractured carbonate reservoir with a relatively low reservoir temperature (52 °C). Enhanced oil recovery (EOR) techniques, such as CO2 flooding and alkaline/surfactant/polymer (ASP) flooding, have been developed to recover the remaining oil after waterflood.6 8 CO2 is miscible with oil at pressures higher than its minimum miscibility pressure and displaces oil miscibly. The sweep efficiency can be improved by water-alternating gas or foam injection. The key problem in applying CO2 flooding is the availability of a large quantity of CO2. Surfactants can be used to lower the interfacial tension (IFT) between oil and water and increase the capillary number to mobilize residual oil blobs.9 Polymers are used to improve the sweep efficiency by providing mobility control.10 Alkali can be used to generate in situ surfactants with acidic oils and increase pH to lower surfactant adsorption.11 13 ASP techniques were initially developed for sandstone reservoirs.14 In the last 10 years, development of ASP techniques for carbonate reservoirs has received considerable attention.15,16 Even then, applications are limited to reservoirs with permeabilities of 20 md and higher because it is difficult to find polymers that can pass through lower permeability rocks and provide mobility control. r 2011 American Chemical Society

If EOR techniques cannot be applied, then the efficiency of the waterflood should be increased. In the last 15 years, it has been shown in sandstones that the ionic composition of the brine affects the waterflood recovery.17 It has been demonstrated that oil recovery from sandstone reservoirs can be improved by the injection of a low-salinity brine with little divalent ions.18,19 It is suspected that low-salinity water changes the wettability to a more water-wet state and releases oil from clays.20 Divalent ions bridge the contact between the clay surface and organic acids in the oil to generate oil wettability; low-salinity brine removes these divalent ions from the solid surface to change the wettability. The impact of brine salinity and ionic composition on oil recovery by waterflood from carbonate rocks has also been studied recently. Researchers have shown that, at high temperatures (>90 °C), seawater injection improves oil recovery from chalks.21 23 The key seawater ions (SO42 , Ca2+, and Mg2+) have the capability to change the rock surface charges, release adsorbed carboxylic oil components, change rock wettability, and improve oil recovery. Hiorth et al.24 propose that mineral dissolution may be a controlling factor in the brine oil chalk interaction. Yousef et al.25 have studied the impact of ion composition on carbonate cores (not chalk) at 100 °C and found that incremental oil recovery is about 10% for 10 times diluted seawater over that of the original seawater. The key mechanism was identified to be the wettability alteration toward a more water-wet state. One of the conditions for the change in wettability because of brine composition in carbonate rocks is the high temperature (>90 °C). These mechanisms are not active at a low reservoir temperature of 52 °C. Received: March 24, 2011 Revised: August 19, 2011 Published: August 22, 2011 3966

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Figure 1. Contact angle, θ, measured between oil and brine on a calcite plate.

Surfactants have been used in the past decade to change the wettability of oil-wet fractured carbonate rocks at low as well as high temperatures. Austad and Milter26 and Standnes and Austad27,28 have conducted a series of studies on wettability alteration in initially oil-wet chalk cores using cationic surfactant solutions and subsequent oil recovery, which can be as much as 70% of initial oil in place. Many6,29 31 have studied the use of anionic surfactants in wettability alteration and oil recovery from fractured carbonates at temperatures from 25 to 90 °C. They have found that IFT can be lowered to low levels (∼10 2 mN/m), wettability can be changed to intermediate wettability (contact angle between 50° and 90°), and laboratoryscale imbibition can be improved (>70% of the initial oil) by the use of very dilute (0.05 wt %) anionic surfactant/alkali solutions. The mechanism seems to be gravity-driven oil flow because of wettability alteration and low tension. In this study, we attempt to improve the secondary waterflood of a low-permeability, nonfractured reservoir at low temperature (52 °C), by adding a surfactant to a high-salinity injection brine. To make the process economically favorable, we have focused our study to low surfactant concentrations, about 0.2 wt %. The contact angle was measured for several surfactants on a calcite plate, and a surfactant was chosen that changed the wettability to an intermediate wettability (contact angle ∼ 90°). Imbibiton studies were conducted with the selected surfactant. Surfactant floods were conducted in the secondary mode and compared to waterfloods. In the next few sections, we describe the methodology for phase behavior studies, wettability studies, and core floods, followed by the observations from laboratory experiments. The last section summarizes our conclusions.

2. METHODOLOGY 2.1. Materials. Synthetic reservoir brine (RB) and injection sea brine (SB) were prepared in the laboratory. The synthetic RB salinity (in equivalent NaCl) is about 81 523 ppm, consisting of 60 340 ppm NaCl, 16 790 CaCl2 3 2H2O, and 13 630 ppm MgCl2 3 6H2O. The synthetic SB used for waterflood contained 32 309 ppm NaCl, 1650 ppm CaCl2 3 2H2O, and 12 550 ppm MgCl2 3 6H2O and had a salinity of 40 826 ppm. Dead crude oil was obtained from the reservoir; it had a viscosity of 4 cP and a density of 0.86 g/mL at the reservoir temperature of 52 °C. It had an acid number of 0.5 mg of KOH/g. Core samples were obtained from the limestone reservoir. The porosity was high (between 20 and 35%), and the brine permeability was very low (between 2 and 5 md). Many surfactants were screened to give non-precipitating solutions with the brines at the reservoir temperature and alter rock wettability from oil-wet to preferentially water-wet. Anionic surfactants are often used along with alkali in carbonate rocks to increase the pH above the point of zero charge to reduce adsorption.31 Many anionic surfactants and alkali have a precipitation problem at this salinity with high divalent ion concentrations.14 About 10 surfactants were tested; some alkyl propoxy sulfates, alkyl propoxy ethoxy sulfates, alkyl ethoxy sulfonates, and secondary alcohol ethoxylates showed compatibility with the injection

Figure 2. Brine drop on an oil-aged reservoir core indicating oil-wet conditions. brine. A secondary alcohol ethoxylate with 15 ethylene oxide (EO) groups (referred to as surfactant E) gave the preferred wettability and is used primarily in this study. 2.2. Wettability. Wettability studies were conducted on mineral calcite plates with various surfactants. The plates were first polished on a 600-mesh diamond plate. These plates were then aged in RB followed by aging with the reservoir oil for 7 days at 90 °C to render them oilwet. The contact angle, θ, is then measured using a goniometer. The contact angle is defined as the angle within the aqueous phase at the oil water solid contact line (Figure 1). A typical water oil contact angle on calcite plates after aging was about 170 180°, indicating oilwet conditions. Then, the oil-aged calcite plates were immersed in a 0.2 wt % surfactant solution in a cuvette at 52 °C. While some of the oil floats, many drops are left behind on the plate. The contact angle of these drops usually changes with time but becomes steady within about 6 h. The final contact angle is measured at 48 h. Once wettability alteration was verified on calcite plates, imbibition experiments were performed on field cores at the connate water saturation (Swc) to verify wettability alteration. Field cores were cleaned and then saturated with the RB by vacuum saturation. The cores were then flooded with the reservoir oil to the connate water saturation and aged for about 40 days at 90 °C. The aging with oil is supposed to restore the wettability of the core to the reservoir wettability. The core is then placed in an imbibition cell filled with the surfactant solution. If the brine imbibes into the core, then oil comes out of the core and floats to the top of the imbibtion cell. The oil collected at the top is monitored as a function of time. If a rock remains oil-wet, then surfactant solutions do not imbibe and no oil is produced. If the rock becomes preferentially water-wet, surfactant solutions imbibe and oil is produced. 2.3. Surfactant Oil Brine (SOB) Phase Behavior. SOB phase behavior controls IFT, viscosity of the phases, macroemulsion 3967

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formation, and precipitation, if any. To prevent the formation of undesirable phases, various chemicals, such as alkali and co-solvent, are often added to the surfactant brine system. Many surfactants were studied and screened. Alkyl propoxy sulfates, alkyl propoxy ethoxy sulfates, alkyl ethoxy sulfonates, and a secondary alcohol ethoxylate (referred to as surfactant E) were some of the surfactants that showed compatibility with the injection brine (0.5 wt % sodium metaborate was added in the case of anionic surfactants). Most of our imbibitions and coreflood studies were conducted with the secondary alcohol ethoxylate (E) because it showed favorable properties. The total surfactant concentration was kept constant at 0.2 wt %. The brine and oil were mixed in a ratio of 1:1. They were kept in a shaker for 3 days and later allowed to equilibrate for 4 more days at 52 °C. The IFT between the equilibrated brine and oil phases was measured using a spinning drop tensiometer. 2.4. Core Flood Procedure. The cores used in the experiments were 1.5 in. in diameter and 3.5 4 in. in length. They were evacuated using a vacuum pump for 4 days and then saturated with the synthetic RB. Oil was then injected until no more brine was produced. Typical initial oil saturations were around 0.8. The cores were then placed in an oven for 45 days at 90 °C to attain there natural wettability (oil-wet). Figure 2 shows one such rock after aging in crude oil. When a drop of brine is placed onto the surface, it does not spread or imbibe into the porous medium. This indicates an oil-wet rock. After aging, they were flooded with a synthetic SB to residual oil saturation, Sor, to simulate waterflooding (WF-1 and WF-2). In a few cores, surfactant flooding was conducted in the secondary mode; i.e., no waterflooding was conducted prior to surfactant injection (WA-1, WA-2, and WA-3). The petrophysical properties of the cores used are listed in Table 1. Oil recovery and

pressure drop were measured. The surface tension (as an indication of the presence of the surfactant in water) of the effluent water was also measured using the pendant drop method in a goniometer (Ramehart model 500).

3. RESULTS AND DISCUSSION 3.1. Phase Behavior Studies. A salinity scan was conducted on surfactant E to observe the phase behavior. Typical surfactant formulations often contain surfactants, alkali, and a co-solvent. Alkali is used to increase injection fluid pH, reduce anionic surfactant adsorption on rocks, and aid in in situ soap generation. Because surfactant E is non-ionic in nature, surfactant adsorption was assumed small, and hence, the addition of an alkali was not required. No alkali or co-solvent was added in this surfactant formulation. The surfactant showed no signs of precipitation, indicating brine compatibility. A salinity scan was conducted on

Table 1. Properties of Cores Used in Experiments property

WF-1

WF-2

WA-1

WA-2

WA-3

diameter (cm)

3.81

3.81

3.81

3.81

3.81

length (cm)

8.9

10.3

10.33

9.5

17.9

porosity (%)

31.8

30.6

31.8

30.06

32.1

brine permeability (md)

4.35

3.67

3.74

4.95

4.24

OOIP (mL)

28

32

29

28

49.5

connate water saturation, Swc

0.13

0.109

0.22

0.14

0.24

oil permeability at Swc (md)

2.5

2.9

2.41

3.25

2.63

Figure 4. (a) Oil-aged calcite plate immersed in a 36 792 ppm brine at 52 °C. (b) Oil drops on an oil-aged calcite plate immersed in a 36 792 ppm brine containing 0.2 wt % surfactant E at 52 °C.

Figure 3. Salinity scan for 0.2 wt % surfactant E from (left) 34 033 to (right) 81 840 ppm brine, showing type II+ phase behavior. 3968

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Table 2. Summary of Secondary Waterfloods

Figure 5. Expulsion of oil from a 3 md carbonate core at 52 °C using 0.2 wt % surfactant E at 36 792 ppm.

surfactant E from 34 033 to 81 840 ppm brine at 52 °C to observe the phase behavior (Figure 3). Different salinities were obtained by diluting the RB with the deionized water. A type II+ kind of system7 was observed throughout this salinity range, where most of the surfactant resides in the oil phase (i.e., the brine phase appeared clear, and the surfactant resided primarily in the oil phase). The IFT was measured to be about 2 6 dyn/cm. 3.2. Wettability Alteration Studies. A typical brine oil contact angle on calcite plates was about 170 180° after aging the calcite plate in the reservoir oil. Naphthenic-acidtype molecules present in the crude adsorb on the positively charged calcite surface, rendering it oil-wet. Oil-aged calcite plates were initially placed in the SB at the reservoir temperature to verify their wettability. Figure 4 shows an oil-aged calcite plate. The oil coats the surface, indicating strong oilwet conditions. Wettability experiments were conducted on mineral calcite plates with several surfactants. When the aged calcite plates were placed in contact with 0.2 wt % surfactant E (non-ionic surfactant) at 36 792 ppm brine salinity, the equilibrated contact angle was found to be about 65 85°, indicating that the wettability had been altered to intermediate-wet conditions. Figure 4 shows the water oil contact angle for this system. A 0.2 wt % propoxy sulfate solution in brine as well as a mixture of 0.15 wt % propoxy sulfate and 0.05 wt % ethoxy sulfonate gave a contact angle of about 160°; the calcite surface remained oilwet. A 0.2 wt % propoxyethoxy sulfate solution gave a contact angle of approximately 78°; the calcite surface was altered to be intermediate-wet. Brine salinity was kept at 36 792 ppm. All of the anionic surfactant solutions also included 0.5 wt % sodium metaborate, but the non-ionic surfactant solution had no alkali. We chose the non-ionic surfactant (E) solution for imbibition and coreflood tests because of the simplicity of formulation and the favorable wettability alteration.

WF-1

WF-2

oil recovery (mL)

18.9

25.5

oil recovery (% OOIP)

67.5

79.6

water injection (PV)

4.6

16

relative brine permeability at Sor

0.27

0.25

oil recovery at 3 PV (% OOIP)

62

62

Figure 6. Comparison of oil recovery during secondary surfactant flood using WA surfactant to that of typical waterfloods.

Once the wettability alteration on a calcite plate was verified, an imbibition experiment was conducted on a carbonate core (2 5 md) to confirm wettability alteration. A (1.5 in. diameter and 3.5 in. long) oil-wet core saturated with oil at Swc was placed in an imbibition cell at 52 °C containing 0.2 wt % surfactant E at 36 792 ppm salinity. Figure 5 shows oil droplets being released from the core because of spontaneous imbibition of surfactant brine. About 20% OOIP was recovered from the imbibition experiment in 7 days. The low recovery rate can be attributed to the fact that the permeability was only 3 md and that the wettability had been altered to intermediate-wet conditions. The gravitational and capillary forces are responsible for the surfactant brine imbibition. While gravitational forces (buoyancy) aid in oil recovery from the top of the core, capillary-driven pressure gradients aid in removal along the periphery of the core.30 No more oil was recovered from the periphery once the capillary-driven pressure gradients became negligible. Because the IFT is not very low (2 6 dyn/cm), this surfactant was not considered for a tertiary flood with oil blob mobilization. It was considered for a secondary surfactant flood because it altered wettability. 3.3. Secondary Waterfloods. The performance of the secondary surfactant floods needs to be compared to secondary SB waterfloods. Several oil-aged cores were waterflooded. Two of them are presented in Table 2 and Figure 6. SB was injected in both the floods at 3 mL/h for several PV. For WF-1, 4.6 PV of SB was injected to recover 67.5% OOIP. Meanwhile, in WF-2, 16 PV of SB was injected to recover 79.6% OOIP. This is a typical characteristic of an oil-wet rock, i.e., high ultimate recovery, but a large amount of water injection to achieve it. Oil tends to coat the surface of the grains; thus, oil occupies smaller pores, and oil relative permeability is low (in comparison to that of a water-wet rock at the same oil saturation). 3969

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Table 3. Summary of Secondary Surfactant Floods secondary surfactant flood

WA-1

WA-2

oil recovery (mL)

26.2

26.5

surf-brine injection (PV)

4

4

Sor

0.14

0.05

oil recovery (% OOIP)

90.3

94.8

oil recovery at 3 PV (% OOIP)

85

86

Figure 8. Surface tension of the effluent brine for WA-2 surfactant flood.

Figure 7. Pressure drop during WA-1 and WA-2 surfactant floods.

The displacement of the oil by brine is unstable to the extent that lower permeability rocks are never invaded by the injection water because of the oil-wet nature and negative capillary pressure. An uneconomical water oil ratio is encountered faster in oil-wet reservoirs in the field scale. In typical field waterfloods, brine is injected for about 2 3 PV. Thus, the oil recovery at 3 PV water injection is an important parameter. The oil recovery at 3 PV is about 62% in these waterfloods. 3.4. Secondary Surfactant Floods. Secondary surfactant floods were conducted to determine if the wettability-altering (WA) surfactant E can improve the recovery rate while maintaining high ultimate recovery. Surfactant brine (0.2 wt % surfactant E in 36 792 ppm salinity brine) was injected in both the floods at 3 mL/h for 4 PV. The results of the floods are given in Table 3. Figure 6 shows a comparison in cumulative oil recovery using a WA surfactant to that of a typical waterflood on a similar rock under similar conditions. For WA-1, breakthrough occurs at about 0.4 PV. The oil recovery is 85% in 3 PV and 90.3% in 4 PV injected. For WA-2, injected water broke through at about 0.4 PV; the oil recovery was 86% at 3 PV and 94.8% at 4 PV injected. The two waterfloods (WF-1 and WF-2) in similar cores are compared to the surfactant floods (WA-1 and WA-2) in Figure 6. Oil recovery is about 62% in the waterfloods at 3 PV injection, whereas it is about 85% OOIP in the secondary surfactant floods. An extra 23% oil was recovered in 3 PV by changing the wettability from oil-wet to intermediate-wet. The oil recovery increases because of the wettability alteration. All of the floods were conducted at the same flow rate of 3 mL/h. Figure 7 shows the pressure drop variation during WA-1 and WA-2. The pressure drops were comparable in both of the cases. They increased to the highest level during water breakthrough and then decreased steadily to a final value of about 5 psi. These pressure drop curves are similar in shape to those of the waterfloods (not shown); the values for the surfactant floods

Figure 9. Upper core is oil-wet (dark in color) after a waterflood, whereas the lower core is intermediate-wet (light gray) after a secondary surfactant flood.

Table 4. Summary of Secondary Surfactant Slug Flood, WA-3 Secondary Surfactant Flood oil recovery (mL)

28.6

surfactant PV injected

1 Post-surfactant Waterflood

oil recovery (mL)

13.8

SB PV injected

2.8

total injection (PV)

3.8

total recovery (% OOIP)

86

oil recovery at 3 PV (% OOIP)

83

were slightly smaller. The IFT of the effluent brine and oil was also measured; it was around 2 dyn/cm, indicating that capillary number is not high (∼5  10 7). Thus, oil mobilization is not the key mechanism of increased oil recovery. The water surface tension variation (as an indication of the presence of surfactant in water) at the outlet was also measured using the pendant drop method in a goniometer for WA-2. It decreased from 53 to 36 dyn/cm (Figure 8), starting at about 0.4 PV, which corresponds to water breakthrough. The surface tension of the injected surfactant 3970

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Figure 10. Comparison of oil recovery during secondary surfactant “slug” flood using WA surfactant to that of typical waterfloods.

Figure 11. Pressure drop during the secondary surfactant “slug” flood.

Figure 12. Surface tension of the effluent brine during the secondary surfactant “slug” flood.

solution was 36 dyn/cm. Lastly, the color of the cores in which wettability had been altered appeared to be less dark (Figure 9) in comparison to a waterflooded oil-wet core. This supports the argument that wettability had indeed been altered on the surface. Wettability alteration (and not IFT) was the key to higher oil recovery and lower remaining oil saturation, Sor. Secondary dilute surfactant floods can be considered to be an effective way of improving oil recovery above waterflood in very low-permeability carbonate rocks. Because these floods do not require high capillary number to reduce the residual oil saturation, high flow rates or pressure gradients are not required, as opposed to the tertiary mode. These floods are similar to waterfloods and probably do not need a mobility control agent (polymers or foams) in multidimensional floods. 3.5. Surfactant Slug Process. After it was concluded that wettability alteration plays a key role in improving recovery rates while maintaining good overall recovery, a surfactant slug injection process (WA-3) was attempted to minimize surfactant injection. A slug of 0.2 wt % surfactant E was injected at the 36 792 ppm brine salinity for 1 PV, followed with SB for 3 PV.

Table 4 below shows the results of the “slug” experiment. Figure 10 compares the oil recovery of the slug experiment to the two conventional waterfloods. The oil recovery at 4 PV injection for the slug process is about 86% OOIP, in comparison to 65% after the conventional waterfloods. The oil recovery at 3 PV total injection is about 83% OOIP. There is no significant difference in oil recovery between a continuous and a (1 PV) secondary surfactant slug flood. Figures 11 and 12 show the pressure drop across the core and the surface tension of the effluent brine. The pressure drops were low, indicating again that a high capillary number is not required to mobilize oil. The brine end point permeability was measured to be about 1.23 md. The surface tension of the effluent was also measured. After 1 PV, the surface tension decreased to about 36 dyn/cm. However, when SB was injected, the surface tension at the outlet increased from 36 to 51 dyn/cm within 1.5 PV of brine injection, indicating the displacement of the surfactant solution by brine. The surface tension midpoint is at about 44 dyn/cm, which corresponds to about 1.85 PV on the x axis, i.e., 0.85 PV after the brine injection. This would indicate a remaining oil 3971

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Energy & Fuels saturation of about 1 0.85 = 0.15, which is consistent with the oil recovery. It is expected that the surfactant slug size can be decreased below 1 PV without hurting the oil recovery significantly, which is the subject of our future research. Adsorption was not studied because we used large slugs of the surfactant, but if the slug size is to be optimized, then surfactant adsorption should be measured.

4. CONCLUSION Wettability alteration on a carbonate rock at a low temperature is studied by the use of a surfactant. The contact angle changes from oil-wet to intermediate-wet in the presence of 0.2 wt % of a surfactant. Brine (without surfactant) does not imbibe into the core spontaneously, but surfactant brine imbibes to the extent of 20% oil in place. Secondary waterflooding recovers about 62% of the oil in about 3 PV injection and 80% in about 16 PV. Secondary surfactant flooding recovers about 85% in about 3 PV and about 90% in 4 PV. Injection of 1 PV of surfactant solution followed by waterflood also recovers about 83% of the oil in a total injection of 3 PV. In typical field waterfloods, 2 3 PV of water is injected. Thus, this increase in oil recovery from 62 to 85% is very significant. Future studies will be directed at optimizing the surfactant slug size. ’ AUTHOR INFORMATION Corresponding Author

*Telephone: 512-471-3077. Fax: 512-471-9605. E-mail: mohanty@ mail.utexas.edu.

’ ACKNOWLEDGMENT This study was partially supported by a grant from the American Chemical Society (ACS) Petroleum Research Fund (PRF) and the Chemical Enhanced Oil Recovery (EOR) Joint Industry Project (JIP) of the Center for Petroleum and Geosystems Engineering. ’ REFERENCES (1) Akbar, M.; Vissapragada, B.; Alghamdi, A. H.; Allen, D.; Herron, M.; Carnegie, A.; Dutta, D.; Olesen, J.-R.; Chourasiya, R. D.; Logan, D.; Stief, D.; Netherwood, R.; Russel, S. D.; Saxena, K. A snapshot of carbonate reservoir evaluation. Oilfield Rev. 2000/2001, 12 (4), 20–21. (2) Roehl, P. O.; Choquette, P. W. Carbonate Petroleum Reservoirs; Springer-Verlag: New York, 1985. (3) Anderson, W. Wettability literature survey—Part 1: Rock/oil/ brine interactions and the effects of core handling on wettability. J. Pet. Technol. 1986, 1125–1142. (4) Anderson, W. Wettability literature survey—Part 2: Wettability measurement. J. Pet. Technol. 1986, 1246–1262. (5) Buckley, J. S.; Liu, Y.; Monsterleet, S. Mechanism of wetting alteration by crude oils. SPE J. 1998, 3 (1), 54–61. (6) Krumrine, P. H.; Falcone, J. S.; Campbell, T. C. Surfactant flooding 1: The effect of alkaline additives on IFT, surfactant adsorption and recovery efficiency. SPE J. 1982, 22, 503–513. (7) Lake, L. W. Enhanced Oil Recovery; Prentice Hall, Inc.: New York, 1989. (8) Manrique, E. J.; Muci, V. E.; Gurfinkel, M. E. EOR field experiences in carbonate reservoirs in the United States. Proceedings of the Society of Petroleum Engineers (SPE)/Department of Energy (DOE) on Improved Oil Recovery Symposium; Tulsa, OK, April 22 26, 2006; SPE 100063.

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