Spontaneous Imbibition of Aqueous Surfactant Solutions into Neutral

Energy & Fuels 2003, 17, 1133-1144

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Spontaneous Imbibition of Aqueous Surfactant Solutions into Neutral to Oil-Wet Carbonate Cores: Effects of Brine Salinity and Composition Skule Strand, Dag C. Standnes,† and Tor Austad* Stavanger University College, P.O. Box 8002, Ullandhaug, N-4068 Stavanger, Norway Received March 5, 2003. Revised Manuscript Received May 21, 2003

Improved oil recovery from oil-wet, low-permeability, and fractured carbonate reservoirs is a great challenge. Water injection based on spontaneous imbibition from the fractures into the matrix blocks, in combination with a wettability alteration process, seems to be an actual method. The present paper adds more important information about the mechanism for wettability alteration of oil-wet carbonate rock, using cationic surfactants of the alkyltrimethylammonium type, in regard to brine salinity and composition. The oil recovery at low temperature (40 °C) is delayed as the salinity increases, because of a decrease in the critical micelle concentration of the surfactant, but the salinity effect seems to vanish at higher temperatures (70 °C). In chalk, improved oil recovery has been observed when sulfate is added to the imbibing fluid, especially at low temperatures (40 °C). At higher temperatures (70 °C), the effects of sulfate also vanish in this case. The catalytic effect of sulfate is of minor importance when dolomite cores are used. A model for the catalytic effect of sulfate is suggested and confirmed by advancing contact-angle measurements on calcite, dolomite, and magnesite crystals.

Introduction Improved oil recovery from an oil-wet, highly fractured, and low-permeability carbonate reservoir is normally regarded as a great challenge, and the recovery is usually very low. Knowing that ∼50% of the world’s known petroleum reserves are present in carbonate rocks, and that ∼90% of these reservoirs are described as neutral to oil-wet, it is easy to understand the importance of research on this topic.1 In an oil-wet rock, water must overcome a capillary barrier to invade the rock matrix to be able to displace the oil in a secondary drainage process. On the basis of the Leverett J*-function, Pc ) σxφ/kJ*, where J* is a dimensionless entry curvature (value usually close to 0.25), σ the oilwater interfacial tension (IFT), φ the fractional porosity, and k the absolute permeability, Al-Hadhrami and Blunt2 made illustrative calculations of the capillary barrier Pc to be overcome, using various improved oil recovery (IOR) techniques. These techniques involved viscous forces, gravity forces, reduction of the oil-water IFT, gas injection, and wettability alteration. The injected fluid will usually bypass the oil-containing matrix blocks, because of the great difference between the permeabilities of the fractures and the matrix blocks. If, however, the rock wettability is altered from * Author to whom correspondence should be addressed. E-mail: [email protected]. † Now with Centre for Integrated Petroleum Research (CIPR), University of Bergen, Norway. (1) Downs, H. H.; Hoover, P. D. In Oil-Field Chemistry, Enhanced Recovery and Production Stimulation; Borchardt, J. K., Yen, T. F., Eds.; ACS Symposium Series 396; American Chemical Society: Washington, DC, 1989. (2) Al-Hadhrami, H. S.; Blunt, M. J. Presented at the Society of Petroleum Engineers/Department of Energy (SPE/DOE) Improved Oil Recovery Symposium, Tulsa, OK, April 3-5, 2000; Paper 59289.

oil-wet to water-wet, a positive value of the capillary pressure Pc is established, and the injected water will spontaneously imbibe from the fractures into the matrix blocks and expel the oil. Wettability alteration, which is the issue of this paper, can be created in two ways, i.e., (i) through the addition of certain surface-active agents (surfactants) to the injection water,3-5 or (ii) through the injection of hot water, usually steam.2 Recently, we have shown that cationic surfactants of the alkyltrimethylammonium bromide (CnTAB) type were able to induce spontaneous imbibition of water into carbonate cores, showing an initially negative capillary pressure Pc (i.e., they did not imbibe pure brine).4 On the basis of a variety of experiments using different surfactants and concentrations, temperatures, crude and model oils, and contact-angle measurements on calcite surfaces, the mechanism for the wettability alteration process was described as a specific interaction between the monomer of the cationic surfactant and strongly adsorbed negatively charged carboxylic material from the crude oil. The strong electrostatic and hydrophobic interaction between the species forms a complex usually termed “a cat-anionic surfactant”.6 The complex is released from the surface and dissolved either in the oil phase or in the surfactant micelles in the aqueous phase. A positive capillary pressure is created, and spontaneous imbibition can take place. The fluid flow mechanism of the spontaneous imbibition (3) Chen, H. L.; Lucas, L. R.; Nogaret, L. A. D.; Yang, H. D.; Kenyon, D. E. SPE Reservoir Eval. Eng. 2001, 4, (February), 16-25. (4) Standnes, D. C.; Austad, T. J. Petrol. Sci. Eng. 2000, 28, 123143. (5) Standnes, D. C.; Austad, T. Colloids Surf. A, 2003, in press. (6) Khan, A.; Marques, E. Catanionic Surfactants. In Specialist Surfactants; Robb, I. D., Ed.; Blakie Academic and Professional: London, 1997; Chapter 3.

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1134 Energy & Fuels, Vol. 17, No. 5, 2003

process can be either counter-current or co-current, depending on the ratio between capillary forces and gravity forces acting on the oil-and-water phase.7 In general, when using surfactants, the spontaneous imbibition rate is usually low, because of a decrease in capillary forces, which is due to the decrease in oilwater IFT value. Furthermore, in a dynamic imbibition process, the rate of the wettability alteration process is dependent on the surfactant monomer concentration, which is dictated by the critical micelle concentration (CMC) value of the surfactant used. The monomeric surfactant concentration is usually at the maximum value at the CMC. Thus, parameters affecting the CMC should also have a strong influence on the imbibition rate. The CMC decreases as the length of the hydrophobic tail of the alkyltrimethylammonium cation increases, and it was observed that dodecyltrimethylammonium bromide (C12TAB) induced an optimal imbibition rate.4 Static wettability alteration studies using calcite surfaces showed that the more hydrophobic the surfactant molecules were, however, the more efficient they were in turning the surface water-wet. In other words, regarding the efficiency of the chemical to induce spontaneous imbibition, a balance between the hydrophobic properties and the CMC is important for an optimal dynamic process in the porous medium.4 It is well-known that the CMC value for surfactants decreases as the salinity of aqueous solution increases, and multivalent ions have greater effects than monovalent ions. Furthermore, the salinity effect on the CMC is usually greater for anionic surfactants, compared to cationic surfactants. Knowing that the brine salinity of carbonate reservoirs can vary in the range of 0.4 g/L (Figure 6). The average oil recovery after 50 days was ∼70%. The oil recovery was reduced when using brine with a sulfate concentration of 0.07 g/L; i.e., 50% was recovered in the same time frame. To visualize the oil expulsion due to the thermal expansion of fluids inside the core and the small heterogeneities in the wetting properties discussed previously,12 a test was performed without C12TAB present (test 23). It is seen that the thermal expansion and fast spontaneous imbibition correspond to an oil recovery of slightly more than 10% of OOIP. Thereafter, very small amounts of oil were recovered.

Imbibition of Aqueous Surfactant Solutions

Energy & Fuels, Vol. 17, No. 5, 2003 1139

Figure 7. Effect of sulfate on the spontaneous imbibition of a 1.0 wt % solution of Arquad into dolomite cores under various conditions ((a) Tim ) 40 °C; Swi ≈ 0.50; permeablity of 101 mD; and (b) Tim ) 40 °C; Swi ≈ 0.45; permeablity of 352 mD). In both cases a and b, brine C was used as the initial water and modifications of this brine were used as theimbibition fluids.

Dolomite Reservoir Cores. It was of great interest to check the catalytic effects of sulfate against other possible carbonate cores at low temperature (40 °C). Two dolomite reservoir cores of different permeability, 101 and 352 mD, were tested. Brine C was used as the initial water (Swi ≈ 0.5), and the same brine at various sulfate concentrations (0.015, 0.15, and 1.5 g/L) was used as the imbibing surfactant solution. The total salinity of the brine was kept constant at ∼0.92 wt % by adjusting the chloride concentration. In this case, the surfactant Arquad was used as the wettability alteration agent. Previous experiments have shown that Arquad behaved quite similar to C12TAB, in regard to imbibition performance.5 The cores were first exposed to the different brines without surfactant for ∼5 days, to confirm that no pure brine was imbibed. The results using the 101 and 352 mD cores are presented in Figure 7a and b, respectively. It is noticed that the imbibition rate and oil recovery were not affected very much by the sulfate concentration, even though they varied by a factor of 100. Thus, chalk and dolomite responded quite differently against the sulfate concentration in the imbibing fluid. This strongly indicates that the catalytic effect caused by sulfate is associated with chemical phenom-

ena at the rock surface, and not in the aqueous solution, as will be discussed later. It is noticed that the oil recovery from the high permeability core was very high (∼90%). Relationship between Salinity and Sulfate. To illustrate the impact of salinity and sulfate on the imbibition process using C12TAB, imbibition tests using brine B at different salinities without sulfate present were performed at 40 °C (Figure 8). The same brine salinity was used in establishing the value of Swi and for the imbibing fluid. No surfactant was present in test 34 with salinity of 4.5 wt %, and the lack of oil production clearly showed that the oil used established a negative capillary pressure. In the presence of C12TAB, the oil recovery during 80 days was very low and quite similar for the salinities 3, 5, and 10 wt % (∼10% of OOIP). Thus, at low temperatures and salinities >3 wt %, C12TAB is rather ineffective in displacing oil from oil-wet, low-permeability chalk by spontaneous imbibition, provided that the injected fluid and initial brine are depleted in sulfate. As expected, the highest recovery was obtained in the case of the lowest salinity (test 32 with a salinity of 1.0 wt %). After ∼80 days, the different imbibing fluids were exchanged by 1.0 wt %


Strand et al.

Figure 8. Effects of salinity and sulfate on spontaneous imbibition of 1.0 wt % C12TAB into chalk cores. Conditions: Tim ) 40 °C and brine B at different salinities without sulfate was used to prepare the cores and as the imbibition fluid for 80 days. After 80 days, seawater (brine D) was used (Swi ≈ 0.25).

Figure 9. Oil-water interfacial tension (IFT) as a function of C12TAB concentration at different sulfate concentrations. Conditions: T ) 40 °C and brine A at different SO42- concentrations with a constant salinity of 4.5 wt %.

C12TAB dissolved in synthetic seawater (brine D, with a salinity of 3.4 wt % and a sulfate content of 2.31 g/L). A drastic increase in imbibition rate took place in all cases, demonstrating the unique catalytic effect of sulfate to improve the imbibition process at low temperature. Oil-Water IFT Measurements. To study the chemical mechanism behind the improved imbibition behavior of sulfate, from a solution point of view, IFT measurements using brine A at different sulfate concentrations (keeping the total salinity constant at 4.5 wt % by adjusting the chloride concentration) were performed. The data are presented in Figure 9. At low surfactant concentrations, the IFT decreased as the surfactant concentration increases, and the minimum in the IFT value is usually related to the CMC value of the system. Within the experimental error, the CMC value was the same for each of the sulfate concentrations (CMC ≈ 0.14

wt %). Thus, the monomer surfactant concentration was mainly determined by the brine salinity (4.5 wt %) and seemed to be independent of the concentration of divalent anions, such as sulfate, in the concentration range tested. Contact-Angle Measurements. Contact-angle measurements on calcite and dolomite surfaces were performed to verify if the effects of sulfate on the imbibition behavior in chalk and dolomite cores could be reflected in the variation of the contact angles. Contact-angle measurements using crystalline magnesite were also included. After depositing the crystals to the oil, the samples were exposed for brines A (containing 1.5 g of sulfate/L) and B (without sulfate) with and without C12TAB present for the same time interval. The salinity of the two brines was constant: 4.5 wt %. Afterward, a drop of distilled water was placed on the surface, and the advancing contact angle was measured through the



Figure 10. Advancing contact-angle measurements on calcite, dolomite, and magnesite under various conditions.

aqueous phase (Figure 10). Examples of the contactangle measurements on magnesite surfaces at different conditions are shown in Figure 11. When exposed to pure brine B without sulfate present, the advancing contact angles for each of the surfaces were ∼80°. In the presence of C12TAB, the contact angle on chalk remained unchanged, whereas it decreased to 45° and 55° for dolomite and magnesite, respectively. Thus, it is confirmed that C12TAB improved the water wetness of dolomite and magnesite somewhat without sulfate being present in the brine, whereas the wetting state of the calcite remained unaffected. In the case of brine A with a sulfate concentration of 1.7 g/L, the contact angles for each of the surfaces decreased somewhat, compared to the values observed using brine B. An average value of ∼70° was observed, which is ∼10° lower. C12TAB dissolved in brine A decreased the contact angle drastically in all cases. The contact angle on chalk and dolomite was ∼30°, whereas it was reduced to 20° for magnesite. In regard to sulfate as a catalytic agent for improved water wetness in combination with C12TAB, it quite obvious that the relative effect is greatest for pure CaCO3, which is completely consistent with the experimental imbibition experiments previously listed. Discussion General Comments. The permeability of carbonate reservoirs, limestone, chalk, and dolomite is usually in the range of 1-100 mD. Under specific conditions, Ma et al.13 scaled the spontaneous imbibition data using the following equation:

td )

xφk(µ σL )t m

2 C

where td is the dimensionless time, k the rock permability (in square meters), φ the porosity (in units of m3/m3), µm is the geometric mean of the water-and-oil viscosity (in units of Pa‚s), LC the characteristic length (13) Ma, S.; Morrow, N. R.; Zhang, X. J. Petrol. Sci. Eng. 1997, 18, 165-178.

Figure 11. Advancing contact-angle measurements on magnesite surfaces after being exposed to (a) pure brine B, (b) brine B containing 1.0 wt % C12TAB, and (c) brine A with a sulfate concentration of 1.7 g/L and 1.0 wt % C12TAB.

(given in meters), σ the oil-water IFT (in units of N/m), and t the imbibition time (given in seconds). The specific conditions were as follows: (i) the wettability must be the same, (ii) relative permeability functions must be the same, (iii) capillary pressure functions must be identically proportional to the interfacial tension, (iv) initial fluid distributions must be duplicated, and (v) gravity must be neglected. Thus, important parameters related to fluid flow in porous media, such as wettability and relative permeability data, are not incorporated in the scaling formula. Furthermore, when working with IOR chemicals, the oil-water IFT is usually reduced, and, in that case, gravity forces must be considered when discussing fluid flow mechanisms. Li and Horne14 recently proposed a scaling method that considered most of these effects; however, it is not the topic of this work. In our experimental work, the oil used had an acid number of AN ) 1.7 mg KOH/g oil, which was high enough to create wetting conditions, preventing the spontaneous imbibition of water.12 We may then conclude that Pc < 0 or the entrance pressure is greater than Pc. Thus, prior to the spontaneous imbibition of water, a wettability alteration must take place in the carbonate pores caused by the cationic surfactant, according to the mechanism described previously.4 In the porous network contacted by the aqueous surfactant (14) Li, K.; Horne, R. Presented at the Society of Petroleum Engineers (SPE) Annual Technical Conference and Exhibition, San Antonio, TX, Sept. 29-Oct. 2, 2002; Paper 77544.


solution, the Pc value becomes positive; however, the value is low, because of the decrease in the IFT (from 20-25 mN/m down to ∼1.0 mN/m). According to the scaling formula of Ma et al.,13 the imbibition rate decreases proportionally as the IFT value decreases. Thus, in addition to the time-consuming wettability alteration process, which is taking place at the carbonate surface, the capillary forces, which are the driving force for spontaneous imbibition, are drastically decreased. Therefore, as observed in the spontaneous imbibition experiments, the process is rather slow. An increase in imbibition rate at conditions of very low IFT and high permeability, because of a change in the driving force, from a capillary-dominated flow regime to a gravity-dominated flow regime,7 has been observed. Salinity Effects. It is important to note that the effects of salinity on the imbibition process must be studied either without sulfate present in the brine or by keeping the sulfate concentration constant in the different tests. Increases in salinity and sulfate concentrations have opposite effects on oil recovery, using the cationic surfactant. In Figure 2, the sulfate concentration was kept constant and was present only in the initial water. The imbibing fluid did not contain sulfate. The drastic decrease in the oil recovery as the salinity increased is explained by a decrease in the CMC, which is related to the concentration of surfactant monomers. The decrease in CMC when electrolytes with a common anion (the ionic strength effect) are added is given by the relationship

ln CMC ) -A ln Ci - B where Ci is the total molar concentration of counterions and A and B both are constants. As an illustration, in the case of C14TAB, A ) 0.696, B ) 4.11, and supposing Ci ) 0.1 and 1.0 M, the calculated CMC values are 0.081 and 0.016 M, respectively.15 Thus, an increase in the salinity by a factor of 10 will cause a decrease in the CMC by a factor of ∼5. The observed salinity effect confirms that surfactant monomers are the active species in the desorption process of carboxylic materials present on the chalk surface.4 It is noticed that the imbibition process performed quite well at very low salinities (0 and 1.0 wt %). It is possible that the sulfate ions present in the initial water will act in a catalytic way at very low salinities. The imbibition behavior seemed to be independent of the salinity at 70 °C, as shown in Figure 3. Thus, increasing the temperature seemed to balance the salinity gradient effect. This observation can be explained by the effect of temperature on the IFT and CMC. Previous work using the pendant drop technique has shown that, for this surfactant-brine-crude-oil system, the IFT value increases as the temperature increases.16 It is also verified from the basic surfactant literature that the CMC of C12TAB-type surfactants increases as the temperature increases in pure water.15,17 Thus, in both cases, the imbibition rate will (15) Zana, R. In Cationic Surfactants: Physical Chemistry; Rubingh, D. N., Holland, P. M., Eds.; Surfactant Science Series 37; Marcel Dekker: New York, 1991. (16) Standnes, D. C. Dr. Ing. Thesis, Norwegian University of Science and Technology (NTNU), Trondheim/Stavanger University College, Tronheim, Norway, 2001.

Strand et al.

increase because of the increase in capillary forces and the increase in surfactant monomer concentration. It must, however, be noticed that solubilization of surfaceactive material from the crude oil into the surfactant micelles will affect the CMC differently, compared to pure water. Even though the increase in temperature from 40 °C to 70 °C make the effect of the salinity gradient of 1.0-10 wt % vanish, the final oil recovery was significantly lower (∼45%, from Figure 3), compared to brine that contains sulfate at similar salinities (∼70%, from Figure 6). Sulfate Effects. The effect of sulfate on the imbibition performance at 40 °C in chalk seems to be dependent on whether initial water is present or not, as shown by Figures 4 and 5. We have no explanation why the sensitivity of sulfate is less without the presence of initial water. With initial water being present, the imbibition behavior was very sensitive to the sulfate concentration, in regard to the imbibition rate and ultimate oil recovery. At 70 °C, there seemed to exist a threshold value of the sulfate concentration, ∼0.1 g/L, above which the imbibition behavior was more or less independent of the sulfate concentration. However, sulfate undoubtedly also has an important role in improving the oil recovery also at 70 °C, but the concentration needed seems to decrease as the temperature increases. Thus, to improve the oil recovery from oil-wet chalk using cationic surfactants of the type C12TAB, sulfate should be added to the imbibing water. In that case, natural seawater should be an excellent IOR fluid to be injected, because it has a sulfate concentration of∼2.31 g/L, as demonstrated by Figure 8. We may then ask the following question: “What is the chemical reason for the observed catalytic effect of sulfate in the imbibition process, which is composed of (i) a wettability alteration process and (ii) an oil displacement process?” The wettability alteration is supposed to take place at the water-oil/solid contact line inside the pores, and the process was previously described as a strong interaction (electrical and hydrophobic) between the cationic monomer surfactant and negatively charged carboxylates that ar adsorbed onto the chalk surface.4 The formed cat-anionic complex, which is usually termed a “cat-anionic surfactant” in the chemical literature, is then released from the surface and dissolved either in the micelles or extracted into the oil phase. Knowing that the impact of sulfate was different for imbibition tests using chalk and dolomite, it is reasonable to believe that the catalytic effects of sulfate are related to the wettability alteration process. Sulfate played a very minor role in the imbibing fluid for both of the dolomite cores tested (Figure 7a and b). This is also confirmed by the advancing contact-angle measurements on calcite and dolomite crystals that are presented in Figure 10. Thus, the trends in the imbibition behavior and the contact-angle measurements using chalk and dolomite are completely agreeable, in regard to the effects of sulfate. The surface charge of carbonates is due to the hydrolysis of surface ions or the adsorption of dissolved species. In the case of dolomite, ∼50% of the Ca2+ (17) Munkerjee, P.; Mysels, K. J. Natl. Stand. Ref. Data Ser. (U.S., Natl. Bur. Stand.) 1971, NSRDS-NBS 36.


cations are replaced by Mg2+ cations. Because of hydrolysis of the solid material, the surface charge can chemically be explained in the following way:10 -CO3 + H2O S -CO3H + OH

-Ca+ + H2O S -CaOH + H+ -Mg+ + H2O S -MgOH + H+ Thus, the surface charge varies with the pH of the solution. In a basic environment, the surface will be negatively charged; under acidic conditions, the surface will be positively charged. The isoelectric point, i.e., the pH value at which the net charge on the surface is zero, is in the range of 7-9.5 for CaCO3, depending on the type and pretreatment of the carbonate material.10,18 Some ions in the equilibrium solution, such as Ca2+, CO32-, and SO42-, can adsorb onto the carbonate material and even change the sign of the zeta potential.10,18 It is then possible to define an isoelectric concentration of the Ca2+, CO32-, and SO42- ions at a given specific pH. Dissolved NaCl behaves as an indifferent electrolyte, and it will have no impact on the zeta potential.10 In carbonate reservoirs, the concentration of Ca2+ cations is usually much higher than the concentration of CO32- anions, which is very often negligible. Sulfate is also a minor component in the initial brine; however, the concentration may be significant when using seawater as the injection fluid. Thus, the relative concentration of Ca2+ and SO42- ions, which, under some circumstances, may dictate the charge on the carbonate surface, can change drastically when going from the initial brine to the injection fluid. As an example, the Ca2+ and SO42- ionic concentrations in the initial Ekofisk brine, which is a chalk reservoir, are 9.27 and ∼0 g/L, respectively, whereas the concentrations in the injected seawater are 0.52 and 2.31 g/L, respectively. A model for the improved imbibition behavior in oilwet chalk when adding SO42- anions to the surfactant solution, which is consistent with the previous discussion, is described in the following way. Suppose that a small amount of organic material adsorbed to the surface is removed by the cationic surfactant. The water will then become in contact with the surface and SO42anions can adsorb onto the initially positive charged carbonate surface and make it partially negatively charged. The positively charged sites on the surface are represented by the metal ions. Because of the local change in surface charge, strongly adsorbed negatively charged carboxylic material is then more easily removed from the surface by the cationic surfactant. In this way, sulfate can act as a catalytic agent in turning the chalk surface more water-wet in the presence of a cationic surfactant. A very interesting question is: “Can sulfate improve the water wetness of oil-wet chalk cores without surfactant present?” Interesting studies on this topic currently are in progress in our laboratory. Knowing that the solubility of CaSO4‚2H2O is ∼100 times lower than that of MgSO4 in cold water, and that the difference even increases as the temperature increases,19 it is quite reasonable to believe that this is (18) Thompson, D. W.; Pownall, P. G. J. Colloid Interface Sci. 1989, 131, (1), 74-82.


also reflected in the affinity of the SO42- anion toward the chalk and dolomite surfaces. This is verified by the different effect of sulfate on the oil expulsion from oilwet chalk and dolomite. In the latter case, sulfate was almost insensitive to the imbibition behavior. The wetting condition of dolomite is more easily changed using a cationic surfactant, compared to pure chalk, probably because of a lower affinity of carboxylic material toward positively charged Mg-centers, compared to Ca-centers. This is also reflected in the much-lower solubility of calcium carboxylates, compared to similar products of magnesium. These arguments are also documented by the advancing contact-angle measurements, showing that the contact angle on dolomite decreased after the surface was treated with surfactant solution without sulfate, whereas the contact angle value on calcite remained unchanged (Figure 10). It is well-known that CMC is dependent on the type of anionic counterion present in the solution of a cationic surfactant. The CMC decreases and the aggregation number increases as the anionic counterions become less hydrated and more polarized, which is consistent with the lyotropic series of anions.20 Sulfate, being a divalent anion, will surely affect the CMC at very low salinities; however, the sulfate concentration did not seem to affect the CMC significantly in brine A with a salinity of 4.5 wt %, even though the sulfate concentration was varied over a range of 0.07-1.7 g/L (Figure 9). In all cases, the CMC was close to 0.14 wt % C12TAB. Thus, consistent with the previous discussion, the catalytic effect of sulfate in turning chalk water-wet must be related to chemical phenomena at the chalk surface and not an increase in surfactant monomer concentration. It is of great interest to note that the IFT passes through a minimum at the CMC value with IFT values in the range of 0.02-0.05 mN/m. At the surfactant concentration used in the imbibition experiments, ∼1.0 wt %, the IFT value was ∼1 mN/m. Thus, the great increase in the IFT value as the surfactant concentration increases above the CMC is very rare and indicates a special interaction between the surfactant and surfaceactive material present in the oil. As the surfactant concentration increases up to the CMC value, the monomers will aggregate at the oil-water interface, together with surface-active materials present in the crude, especially carboxylates (remembering that the acid number of the crude was AN ) 1.7 mg KOH/g of oil). Thus, anionic and cationic surface-active material packed closely at the liquid-liquid interface will result in a very low IFT value. As micelles are formed at higher surfactant concentrations, anionic surface-active material from the oil will solubilize into the formed micelles, and the close packing of surface-active material at the liquid interface is not maintained. The interface will contain a large excess of cationic surfactants with greater electrostatic repulsion between the headgroups, causing this unusually large increase in the oil-water IFT value. (19) Weast, R. C., Ed. Handbook of Chemistry and Physics, 52th ed.; The CRC Press: Boca Raton, FL, 1971. (20) Underwood, A. L.; Anacker, E. W. J. Colloid Interface Sci. 1987, 117, (1), 242-250.


Conclusions Improved oil recovery (IOR) from oil-wet, low-permeability, and fractured carbonate reservoirs is a great challenge. Water flooding that is based on spontaneous imbibition, in combination with a wettability alteration process, seems to be an actual method. The present paper adds more important information to the mechanism for wettability alteration in oil-wet carbonate rock using cationic surfactants of the alkyltrimethylammonium type. The following conclusions are drawn: (1) At low temperature (40 °C), the spontaneous imbibition performance decreased as the injected brine salinity increased. At higher temperature (70 °C), the decrease in imbibition behavior seemed to vanish as the salinity increased, which was explained by temperature effects on the IFT and critical micelle concentration (CMC) value. (2) Sulfate present in the imbibing fluid was observed to improve the spontaneous imbibition behavior. The effect was more pronounced at low temperature. At higher temperature, the catalytic effect of sulfate was smaller, but it had a significant effect on ultimate oil recovery. It was noticed that the decrease in imbibition performance at higher salinities more or less could be compensated by adding sulfate to the surfactant solution. (3) Sulfate concentration had a much lesser effect on the imbibition performance into oil-wet dolomite cores, compared to chalk cores, suggesting that the improvement by sulfate was related to the chalk surface. This was also confirmed by separate advancing contact-angle measurements on calcite and dolomite crystals. (4) The experimental results are consistent with a model that involves the adsorption of sulfate onto the water-wet zones of the chalk, changing the surface charge so that the cationic surfactant can remove strongly adsorbed carboxylic material more easily. Abbreviations A ) constant in the formula describing the variation of the CMC when an electrolyte is added AN ) acid number (in units of mg KOH/g oil) Arquad ) Arquad MC-50 B ) constant in the formula describing the variation of the CMC when an electrolyte is added Ch ) chalk core

Strand et al.

CMC ) critical micelle concentration (in units of wt %, M) Ci ) total concentration of counterions (in units of M) CnTAB/CnTACl ) surfactants of the type CnH2n+1N(CH3)3Br/CnH2n+1N(CH3)3Cl C12TAB ) dodecyltrimethylammonium bromide, C12H25N(CH3)3Br D ) diameter of core (given in centimeters) Do ) dolomite core HCPV ) hydrocarbon pore volume (given in cubic centimeters) IFT ) interfacial tension (in units of mN/m) IOR ) improved oil recovery J* ) dimensionless entry curvature (the value usually is ∼0.25) k ) absolute permeability (in units of m2, mD) L ) core length (given in centimeters) LC ) characteristic length (given in meters) OOIP ) original oil in place (given in cubic centimeters) PV ) pore volume (given in cubic centimeters) Pc ) capillary pressure (in units of Pa‚s) pH ) -log[H3O+] Swi ) initial water saturation (given as a fraction or a percentage) T ) temperature (given in degrees Celsius) Tim ) imbibition temperature (given in degrees Celsius) TDS ) total dissolved solid (in units of g/L) t ) imbibition time (given in days or seconds) td ) dimensionless time wt % ) weight percentage φ ) porosity (given as a fraction or a percentage) µm ) geometric mean of oil and water viscosity (in units of Pa‚s) σ ) oil-water IFT (in units of mN/m) Acknowledgment. The authors wish to thank Statoil and Reslab for delivering the crude oil and Dr. Peter Frykman (Geological Survey of Denmark and Greenland (GEUS), Copenhagen, Denmark) for providing the chalk material. Also, thanks to Akzo Chemicals Ltd., United Kingdom, for supplying the surfactant Arquad MC-50 and our colleague, Associate Professor Dag E. Ormaasen, for supplying the carbonate crystals. D.C.S. greatly appreciates the financial support from Statoil. EF030051S

Spontaneous Imbibition of Aqueous Surfactant Solutions into Neutral

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