Determination of Wettability and Its Effect on Waterflood Performance

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Energy & Fuels 2004, 18, 438-449

Determination of Wettability and Its Effect on Waterflood Performance in Limestone Medium Ugur Karabakal† and Suat Bagci*,‡ Turkish Petroleum Corporation Research Center, Ankara, Turkey, and Department of Petroleum and Natural Gas Engineering, Middle East Technical University, 06531, Ankara, Turkey Received January 9, 2003. Revised Manuscript Received December 3, 2003

Wettability measurement methods, the effect of wettability on fluid distribution, and fluid flow in porous media were discussed, and the influence of rock wettability on the relative permeability and recovery of oil by waterflooding were investigated. Experimental studies were conducted on a total of 23 core plugs from two different limestone formations. Synthetic brine (NaCl solution) and mineral oil, which has a viscosity ratio of ∼10, were used as the test fluids. Core samples, saturated with synthetic brine, were flushed with mineral oil to establish the initial conditions, and the wettability of the samples was measured by the Amott-Harvey method. Test results showed that the wettability of the samples ranged from strongly water-wet to intermediately wet. Wettability measurements were repeated and showed that the Amott-Harvey wettability indices were reproducible. The effects of aging time, brine salinity, and saturation procedure on wettability were examined. Long-time aging in mineral oil altered the wettability of a water-wet core sample to intermediately wet. Unfortunately, there was only one water-wet sample, and correlation of the alteration of wettability, with respect to aging time, was not possible. Increasing the brine salinity also reduced the water wetness. However, the saturation procedure had almost no effect on the wettability of the core samples. Aging could not alter the wettability of the intermediately wet samples, by varying brine salinity and by changing saturation procedure; therefore, it was concluded that intermediate wettability was more stable than water wetness. Relative permeability and waterflood studies were conducted on core samples that had different wettability levels. In a water-wet medium, water breakthrough occurred relatively late and a considerable amount of oil was produced before the breakthrough. After the breakthrough, the rate of oil production was decreased very sharply. Decreasing the water wetness resulted in decreasing the breakthrough recovery. In the intermediately wet system, breakthrough occurred very early and most of the oil was produced after the breakthrough. Water breakthrough had almost no effect on the rate of oil production. Waterflood in the water-wet system seemed more economical, because a lesser volume of water was required to produce the same amount of oil.

1. Introduction Oil recovery from porous sedimentary rocks is dependent mainly on the overall efficiency with which oil is displaced by some other fluid(s). In this process, the wettability of reservoir rock is as important as the permeability, viscosity, and fluid saturations in determining the characteristics of multiphase flow (Donaldson et al.1). Wettability is the major factor that controls the spatial distribution of fluids in a reservoir (Anderson2,3). In a strongly water-wet rock initially at the irreducible water saturation, water, which is the wetting * Author to whom correspondence should be addressed. E-mail: [email protected]. † Turkish Petroleum Corporation Research Center. ‡ Middle East Technical University. (1) Donaldson, E. C.; Thomas, R. D.; Lorenz, P. B. Wettability Determination and Its Effect on Recovery Efficiency. SPE J. 1969, 25, 13-20. (SPE Paper No. 2338.) (2) Anderson, W. G. Wettability Literature Survey. 5. The Effect of Wettability on Relative Permeability. JPT, J. Pet. Technol. 1987, 39 (November), 1453-1468. (SPE Paper No. 16323.) (3) Anderson, W. G. Wettability Literature Survey. 6. The Effect of Wettability on Waterflooding. JPT, J. Pet. Technol. 1987, 39 16051622. (SPE Paper No. 16741.)

phase, will occupy the small pores and form a thin film over all the rock surfaces. Oil, which is the nonwetting phase, will occupy the centers of the larger pores. Any oil located in the small pores would be displaced into the center of the larger pores by spontaneous water imbibition, which is an important phenomenon in oil recovery, especially in fractured reservoirs where the rate of mass transfer between the rock matrix and the fractures determines the oil production.4-7 If a rock is strongly oil-wet, it is preferentially in contact with the (4) Zhou, X.; Torsaeter, O.; Xle, X.; Morrow, N. R. The Effect of Crude Oil Aging Time and Temperature on the Rate of Water Imbibition and Long-Term Recovery by Imbibition. Presented at the SPE 68th Annual Technical Conference and Exhibition (Houston, TX, October 3-6, 1993). (SPE Paper No. 26674.) (5) Zhang, X.; Morrow, N. R.; Ma, S. Experimental Verification of a Modified Scaling Group for Spontaneous Imbibition. SPE Reservoir Eng. 1996, 11 (11), 280-285. (SPE Paper No. 30762.) (6) Graue, A.; Viksung, B. G.; Baldwin, B. A. Reproducible Wettability Alteration of Low-Permeable Outcrop Chalk. Presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, OK, April 1922, 1998. (SPE Paper No. 39622.) (7) Ma, S. M.; Zhang, X.; Morrow, N. R.; Zhou, X. Characterization of Wettability from Spontaneous Imbibition Measurements. J. Can. Pet. Technol., 1999, 38 (13). (Special Edition.)

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Wettability and Waterflood Performance in Limestone

oil and the location of the two fluids is reversed from the water-wet case and the connate water saturation seems to be located as separate droplets in the centers of the pore spaces. Most of the clean rock mineral surfaces have a tendency to be preferentially wet by water rather than by crude oil.8-10 However, the original strong water wetness of most reservoir minerals may be altered by the adsorption of polar compounds and/or the deposition of organic matters that are included in the crude oil.11-13 Pore structure, mineralogy, pH and salinity of the brine, reservoir temperature, and historical maximum capillary pressure are reported as factors that control the wettability of a reservoir.8,14 The wettability of a core sample affects all types of special core analyses, including capillary pressure, relative permeability, waterflood behavior, electrical properties, and simulated tertiary recovery, and the analysis should include the effects of wettability variation. Craig13 defined wettability as “the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids”. Anderson12 defined the wettability for a crude oil/brine/rock system as the measure of the preference that the rock has for either the oil or the water. The wettability of the rock/fluid system is important, because it is the major factor that controls the location, flow, and distribution of fluids in a reservoir. Wettability studies showed that reservoir wettability could cover a broad spectrum of wetting conditions, from very strongly water-wet to very strongly oil-wet. For simplicity, it is generally assumed that the pore surface within a reservoir rock is uniformly wetted. Water-wet, oil-wet, and intermediate-wet states are uniform wettability states in which every portion of the entire rock surfaces shows the same preference for oil and water. However, many reservoirs have heterogeneous wettability, where some portions of the rock surface are water-wet while others are oil-wet. This nonuniform wettability state is called fractional wettability, and it is more common than the uniform wettability state. Mixed wettability is a special type of fractional wettability in which the oil-wet surfaces form continuous paths through the larger pores. The smaller pores remain water-wet and contain no oil, and all the oil in a mixed-wet reservoir is located in the larger oil-wet pores. This results in a small, but finite, oil permeability that is permitted to exist down to very low oil saturation and permits the drainage of oil during a waterflood to (8) Chang, Y. C.; Mohanty, K. K.; Huang, D. D.; Honarpour, M. M. The Impact of Wettability and Core-Scale Heterogeneities on Relative Permeability. J. Pet. Sci. Eng. 1997, 18, 1-19. (9) Gant, P. L.; Anderson, W. G. Core Cleaning for Restoration of Native Wettability. Presented at the SPE Rock Mountain Regional Meeting, MT, May 19-21, 1986. (SPE Paper No. 14875.) (10) Dullien, F. A. I.; Allsop, H. A.; Macdonald, I. F.; Chatzis, I. Wettability and Immiscible Displacement in Pembina Cardium Sandstone. J. Can. Pet. Technol. 1990, 29 (4), 63-74. (11) Morrow, N. R. Wettability and Its Effect on Oil Recovery. J. Pet. Technol. 1990, (December), 1476-1484. (12) Anderson, W. G. Wettability Literature Survey. 1. Rock/Oil/ Brine Interactions and the Effect of Core Handling on Wettability. JPT, J. Pet. Technol. 1986, 38 (October), 1125-1144. (SPE Paper No. 13932.) (13) Craig, F. F. The Reservoir Engineering Aspects of Waterflooding; SPE Monograph Series, Vol. 3; Society of Plastics Engineering (SPE): Dallas, TX, 1971. (14) Anderson, W. G. Wettability Literature Survey. 2. Wettability Measurements. JPT, J. Pet. Technol. 1986, 38 (November), 1246-1262. (SPE Paper No. 13933.)

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continue until very low oil saturations are reached. To understand the reservoir wettability, displacement tests should be conducted under conditions that are representative of the reservoir. Thus, cores with unaltered wettability are essential. This requires coring, core recovery, storage, and testing procedures to be designed to recover the cores without changing the surface properties. Factors that affect the wettability during testing are reported to include (i) properties of the test fluids (such as salinity), (ii) test temperature, (iii) aging time and temperature, and (iv) established initial water saturation.15-17 Tang and Morrow18 studied the effect of each parameter and concluded that increases in the rate of water imbibition translates to increases in water wetness, whereas a decrease in the same parameter results in an increase in oil wetness. Jadhunandan and Morrow15 conducted 50 slow-rate laboratory waterfloods to study the effect of wettability on oil recovery. Wettability, with respect to water, decreased markedly as the aging temperature increased and the initial water saturation decreased. 1.1. Effect of Wettability on Relative Permeability. Wettability affects the relative permeability by controlling the flow and spatial distribution of fluids in a porous medium. In strongly wetted rock, the relative permeability of the nonwetting phase is dependent on the saturation path, whereas the relative permeability of the wetting phase is often independent of the path (from Chang et al.8). The relative permeability of the wetting phase is a function only of its own saturation and is not influenced by the direction of saturation change or the nature of the nonwetting phase. At any given saturation, as the degree of rock preferential water wettability decreases, the relative permeability to oil decreases and the relative permeability to water increases, as shown in Figure 1 .13,18-20 In a uniformly wetted system, the wetting fluid will generally be located in the smaller pores and as a thin film in the larger pores, whereas the nonwetting fluid is located in the centers of the larger pores. In general, at a given saturation, the relative permeability of a fluid is greater when it is the nonwetting phase. For example, the relative permeability of water is larger in an oilwet system than it would be if the system were waterwet. This occurs because the wetting fluid has a tendency to travel through the smaller, less-permeable pores, whereas the nonwetting fluid travels more easily (15) Jadhunandan, P. P.; Morrow, N. R. Effect of Wettability on Waterflood Recovery for Crude Oil/Brine/Rock Systems. Presented at the SPE 66th Annual Technical Conference and Exhibition, Dallas, TX, October 6-9, 1991. (SPE Paper No. 22597.) (16) Jia, D.; Buckley, J. S.; Morrow, N. R. Control of Core Wettability with Crude Oil. Presented at the SPE International Symposium on Oil Field Chemistry, Anaheim, CA, February 20-22, 1991. (SPE Paper No. 21041.) (17) Tang, G. Q.; Morrow, N. R. Effect of Temperature, Salinity and Oil Composition on Wetting Behaviour and Oil Recovery by Waterflooding. Presented at the SPE Annual Technical Conference and Exhibition, Denver, CO, October 6-9, 1996. (SPE Paper No. 36680.) (18) Raza, S. H.; Treiber, L. E.; Archer, D. L. Wettability of Reservoir Rocks and Its Evaluation. Prod. Mon. 1968, 32 (4), 2-7. (19) Owens, W. W.; Archer, D. L. The Effect of Rock Wettability on Oil-Water Relative Permeability Relationship. JPT, J. Pet. Technol. 1971, 23 (July), 873-878. (SPE Paper No. 3034.) (20) Donaldson, E. C.; Thomas, R. D. Microscopic Observations of Oil Displacement in Water-Wet and Oil-Wet System. Presented at the SPE Annual Meeting, New Orleans, LA, October 3-6, 1971. (SPE Paper No. 3555.)

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Figure 1. Effect of wettability on the relative permeability of a rock/oil/brine system (from Raza et al.18).

in the larger pores. In addition, at lower nonwetting phase saturation, the nonwetting phase will become trapped as discontinuous globules in the larger pores. These globules block pore throats, reducing the relative permeability of the wetting phase. On the other hand, the relative permeability of the nonwetting phase is high, because the nonwetting phase flows through the centers of the larger pores. At low wetting phase saturations, the effective permeability of the nonwetting phase will often approach the absolute permeability, demonstrating that the wetting phase does not greatly restrict the flow of the nonwetting phase (according to Anderson2). 1.2. Effect of Wettability on Waterflood Performance. Dullien et al.10 noted that, although macroscopicto-megascopic reservoir heterogeneities affect waterflood performance, oil displacement occurs at the pore level, and the microscopic displacement mechanisms must be determined. The microscopic efficiency of oil recovery is primarily influenced by the wettability, the saturation history, the viscosity ratio, and the pore structure. It is generally accepted that a waterflood in a strongly waterwet rock is more efficient than that in an oil-wet rock. However, there is less agreement regarding the comparison of the waterflood performance of water-wet and intermediate-wet systems. Some researchers (such as Owens and Archer19 and Donaldson and Thomas20) noted that oil recovery was reduced as the wettability was changed toward less-water-wet conditions. However, other researchers (such as Graue et al.,6 Ma et al.,7 and Morrow11) reported that oil recovery increases as water-wetness decreases and passes through a maximum when the system has intermediate wettability. A waterflood in a strongly oil-wet rock is much less efficient than that in a water-wet rock. When the waterflood begins, the water will form continuous channels or fingers through the centers of the larger pores, pushing the oil in front of it, and early water breakthrough occurs. As water injection continues, water invades the smaller pores to form additional continuous channels, the water:oil ratio of the produced fluids gradually increases, and oil flow falls to a very low level. Oil recovery before breakthrough is relatively small, with most of the oil being produced after breakthrough.

Karabakal and Bagci

The residual oil after the waterflood is found (i) filling the smaller pores, (ii) as a continuous film over the pore surfaces, and (iii) as larger pockets of oil trapped and surrounded by water. Because much of this oil is still continuous through the thin oil films, it may still be produced at a very slow rate. The residual oil saturation is not well-defined. In contrast to the water-wet case, oil recovery is strongly dependent on the volume of water injected.3,20,21 As previously described, a mixedwettability system has continuous oil-wet paths through the larger pores, whereas the small pores are waterfilled. Such a system combines the best aspects of waterwet and oil-wet systems. Compared with a water-wet system, trapping is reduced in the large, oil-wet pores. Compared with an oil-wet system, trapping is reduced because the small pores in a mixed-wet system are water-filled. When mixed-wet cores are waterflooded, film drainage causes very low residual oil saturations. After the injection of many pore volumes (PVs) of water, a small but finite permeability to oil exists, even at very low oil saturations (according to Anderson3 and Ma et al.7). The aim of this study includes (i) measurement of the wettability, (ii) investigation of the possibility of changing or artificially controlling the wettability of the core samples, and (iii) examination of the effect of wettability on the relative permeability and waterflood performance, in a limestone medium. 2. Experimental Equipment, Materials, and Procedures 2.1. Experimental Equipment. The porosity of the core samples was determined using a helium gas expansion porosimeter. A gas permeameter determined the absolute air permeability of the core samples. The core flooding system consists of a constant-volume positive displacement pump, two accumulators (one for oil and another for brine), a pressure gauge for the determination of inlet pressure, and a triaxial core holder. The schematic diagram of the core flooding system is shown in Figure 2. The spontaneous brine imbibition experiment was performed using the imbibition apparatus that is schematically shown in Figure 3. Figure 3 shows that the apparatus basically is a simple glass container that has a graduated glass cap. To perform a spontaneous imbibition test (for example, brine imbibition), a core sample at an initial water saturation Swi is immersed in the glass container that is filled with brine. Because of capillary imbibition, oil is displaced from the core sample by imbibition the brine. The displaced oil is accumulated in the graduated cap by gravity segregation. 2.2. Experimental Materials. The core samples used in this study were taken from two different limestone formations: 18 samples (sample numbers 51-69) from Formation M-1 (Mardin formation) and 5 samples (sample numbers 7175) from Formation B-1 (Beloka formation). The cores were cut into pieces 3.8 cm in diameter and 4-7 cm in length. Air permeability of the samples was measured, varying over a range of 2-80 md, and the porosity was in the range of 9%20%. The absolute permeability to brine was in the range of 0.43-31.62 md. Detailed information about the core samples is given in Table 1. The brines used in the experiments were NaCl solutions of different salinities, in the range of 10 00060 000 ppm. Most of the measurements were performed using (21) Salathiel, R. A. Oil Recovery by Surface Film Drainage in Mixed-Wettability Rocks. JPT, J. Pet. Technol. 1973, 25 (October), 1216-1224. (SPE Paper No. 4104.)



Figure 2. Schematic diagram of the core flooding system.

Figure 3. Spontaneous imbibition apparatus.

Figure 5. Viscosity and density of the 10 000 ppm NaCl solution at elevated temperature.

Figure 4. Viscosity and density of mineral oil at elevated temperature. the 10 000-ppm solution. Mineral oil was used as the oil phase in the experiments. The relationship of the viscosity and density of the mineral oil, versus temperature, is shown in Figure 4, and that of the brine is shown in Figure 5. 2.3. Experimental Procedures. Air permeability of the plug samples was measured using the gas permeameter. The permeability resulted from the injection of dry air into the clean and dry sample. At a constant differential pressure, dry air was injected through the sample until a constant flow rate was attained. The permeability then was calculated using the appropriate form of the Darcy equation, which is derived for compressible fluid flow through porous media. The dry and clean sample with known porosity and permeability was evacuated for 8 h, using a vacuum pump. The

sample then was saturated by pressurizing up to 1000 psig (using a positive displacement pump) and using brine as the displacing phase. After the core samples were saturated with brine, a period of ∼2 days was allowed for the brine to achieve ionic equilibrium with the rock. After saturation with brine, the core sample was inserted into a Hassler-type core holder and a net confining pressure of 500 psig was applied. Brine permeability resulted from the injection of brine into the samples at a constant flow rate until a constant pressure of the brine through the sample was attained. After measurement of the absolute brine permeability, oil was flooded through the core samples until no more water was produced and the Swi value was established. The samples then were immersed in a mineral oil bath and placed in a temperaturecontrolled oven. Temperature was set to 70 °C. The aging period was standardized at 30 days for all tests performed in Measurements I and II. To investigate the effect of aging time on the wettability of the core samples, the aging period was varied over a range of 30-70 days. 2.4. Determination of Core Wettability. The wettability of the core samples was determined by the Amott-Harvey Method,22 after 30-70 days of aging in mineral oil at a temperature of 70 °C. Test results were expressed using the (22) Amott, E. Observations Relating to the Wettability of Porous Rock. Trans. AIME 1959, 216, 156-162.

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Table 1. Petrophysical Properties of the Core Samples Kair (md)

grain density, F (g/cm3)

plug number

length (cm)

diameter (cm)

51 52 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69

6.29 5.03 6.77 6.22 4.89 6.17 5.93 6.86 6.48 6.75 6.64 6.54 6.75 6.63 6.99 6.86 6.53 4.66

3.70 3.70 3.70 3.70 3.70 3.70 3.70 3.70 3.70 3.70 3.70 3.70 3.70 3.70 3.70 3.70 3.70 3.70

M-1 Formationa 5.01 30.14 2.49 7.24 4.08 8.84 12.93 8.85 10.42 12.14 6.31 5.84 4.09 8.84 17.54 2.00 80.26 12.86

71 72 73 74 75

4.88 4.04 4.42 4.52 4.43

3.70 3.71 3.71 3.71 3.71

B-1 Formationb 18.99 10.43 34.18 5.96 28.58

pore volume, PV (cm3)

porosity (%)

2.67 2.66 2.69 2.70 2.71 2.67 2.67 2.70 2.69 2.69 2.71 2.70 2.71 2.68 2.70 2.70 2.71 2.71

7.26 10.78 9.26 8.03 6.16 10.73 11.24 9.72 12.09 11.08 8.54 9.06 9.76 13.81 12.48 6.33 14.41 9.15

10.74 19.93 12.72 12.00 11.71 16.18 17.63 13.17 17.35 15.27 11.96 12.89 13.44 19.38 16.61 8.59 20.52 18.26

2.70 2.68 2.67 2.69 2.68

10.33 7.47 8.56 7.55 8.26

19.69 17.11 17.91 15.44 17.26

a M-1 samples (samples 51-69): limestone, light brown in color; is cryptocrystalline, hard, and brittle; has interparticle microporosity and small vugs. b B-1 samples (samples 71-75): limestone, light gray in color; has calcite fillings between the particles; is hard and brittle; has interparticle and vuggy porosity.

Amott-Harvey relative displacement index (IAH). To determine the wettability index, each brine-saturated core sample was flooded with oil to reach its irreducible water saturation and the following steps were performed: (i) spontaneous brine imbibition, (ii) forced brine displacement, (iii) spontaneous oil imbibition, and (iv) forced oil displacement. The spontaneous brine imbibition experiment was performed using the spontaneous imbibition apparatus. To perform the imbibition test, a core sample was immersed in the glass container that was filled with brine solution. Because of capillary imbibition, oil was displaced from the core sample by the imbibing brine. The displaced oil accumulated in the graduated cap by gravity segregation. At the end of the experiment, the total volume of produced oil was recorded. Before the oil volume reading was taken, the container was gently shaken to expel oil drops that were adhering to the core surface and the lower portion of the cap, so that all the produced oil accumulated in the graduated portion of the glass cap. After the spontaneous imbibition in brine was completed, the core sample was placed in the Hassler-type core holder and subjected to forced displacement by brine. Depending on the transmissibility capacity of the plug sample, an appropriate flow rate was used. At the end of the test, the amount of oil produced was recorded. After the brine displacement test was completed, the spontaneous oil imbibition experiment was performed using the spontaneous imbibition apparatus. However, the glass container was turned upside down and filled with oil. The displaced water was accumulated in the graduated cap by gravity segregation. At the end of the experiment, the glass container was gently shaken again, for the same reason explained previously, and the total volume of produced water was recorded. After the spontaneous imbibition in oil was completed, the core sample was subjected to forced displacement by oil, using an appropriate flow rate. The experimental conditions are given in Table 2. At the end of the test, the amount of oil produced was recorded.

Table 2. Experimental Conditions for Spontaneous Oil Imbibition Runs

a

plug number

test temperature (°C)

flow rate (cm3/h)

52 54 68 71 73 74a 74b 75

74 73 74 78 78 73 75 72

25 20 25 25 35 45 45 20

First run. bSecond run.

3. Experimental Results and Discussion Experimental studies were conducted on 23 core samples. All the samples were cleaned and their petrophysical properties were determined. Wettability of the samples then was measured, using mineral oil and a 10 000 ppm NaCl solution, and the first group of the tests was completed. In the second part of the study, to be sure that the test conditions and techniques were sufficient to repeat the measurements, the core samples were cleaned by the conventional Soxhlet extraction technique with hot toluene and the wettability tests were repeated. Similar test results were obtained. Finally, the wettability of the core samples was altered artificially by changing the saturation procedure and the salinity of the brine, and by aging the core samples in mineral oil for different lengths of time. Using core samples with different wettability indices, relative permeability measurements and waterflood recovery calculations then were perfomed. The order of the tests conducted on each core sample is given in Table 3. All the wettability test results for Measurement II are given in Table 4. 3.1. Wettability Studies. 3.1.1. First Group of Experiments. At the end of the first group of measure-



Table 3. Order of the Tests Conducted on Each Plug Samplea sample number

φ

1st Group k F I

2nd Group k F I

φ x x x x x x x x x x x x x x x x x x

x x x x x x x x x x x x x x x x x x


B-1 Formation • x • x • x • x • x

x x x x x

x x x x x

x x x x x

φ

51 52 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69




M-1 Formation x • x x • x x • x x • x x • x x • x x • x x • x x • x x • x x • x x • x x • x x • x x • x x • x x • x x • x

71 72 73 74 75

x x x x x

x x x x x

x x x x x

x x x x x

3rd Group k F I x x x x

kr

x x

x x x x x x

x

x x x x x

x x xb x

a Symbol legend for the table is as follows: φ, porosity; k, air permeability; F, grain density; I, wettability; and kr, relative permeability. A checkmark (x) indicates that the test was performed in the experiment, whereas no checkmark indicates that the test was not performed in the experiment. b Measured two times, for two different wettability conditions.

ments, the B-1 samples (samples 71-75) were determined to be moderately water-wet to strongly waterwet. The Amott-Harvey wettability index (IAH) values were 0.56-0.92. However, all the M-1 samples showed intermediate wet characteristics and the wettability indices were very close to zero. During the wettability measurements, irreducible fluid saturations and the endpoint relative permeability were also determined. There was a very good correlation between the endpoint relative permeability of the water (krw at Sor) data and the wettability characteristics of the core samples. The relative permeability values of the water-wet samples were all lower than the intermediate-wet ones, corroborating results by Craig.13 However, Morgan and Gordon23 proposed that, besides the wettability, a similar effect could also be caused by the differences in the pore size distribution of the core samples. Variations of the endpoint relative permeability, with respect to the wettability characteristics of the core samples, are shown in Figure 6. 3.1.2. Second Group of Experiments. In the second part of the study, all the core samples were cleaned by Soxhlet extraction and the wettability of all the samples was measured again, to verify that the wettability indices of the core samples were reproducible. The results of the second set of measurements showed good consistency between the two data sets. Wettability indices obtained from the first group of experiments (Measurement I) and the second group of experiments (Measurement II) are compared in Figure 7. (23) Morgan, J. T.; Gordon, D. T. Influence of Pore Geometry on Water-Oil Relative Permeability. JPT, J. Pet. Technol. 1970, 22, 1199-1208.

3.1.3. Third Group of Experiments. The purpose of this part of the experiment was to determine the effect of salinity, aging period, and saturation procedure on wettability. For this purpose, plug samples were cleaned and three sets of samples, each having five plugs with a wettability distribution that is as homogeneous as possible, was arranged. The first set of samples was used to determine the effect of salinity on the wettability of the core samples. The wettability of the each core sample was determined using different brine samples, the salinity of which changed over the range of 20 00060 000 ppm. The second set of samples was used to determine the effect of aging period on the wettability of the core sample. After establishing the Swi value of each sample, the core samples were aged by immersion in mineral oil. The aging temperature was kept constant at 70 °C by a temperature-controlled oven. The aging periods were varied over a range of 30-70 days. The third set of samples was used to determine the effect of saturation procedure on the wettability of the core sample. After cleaning, the core samples were saturated with 100% mineral oil instead of brine. The wettability of the samples then was determined. The results of the third group of experiments are compared with the measurements of the first two groups in Figures 8, 9, and 10. The wettability of the M-1 samples (samples 55-60) did not change by aging, although the duration was very long (63 days for sample 68). The measured IAH values for the M-1 samples were very similar to the first two measurements, indicating no significant change in wettability. However, aging changed the wettability of the B-1 sample (sample 74) from the water-wet condition to the intermediate-wet condition. There was a significant change in the wettability index of the sample, from 0.67 to 0.0. Unfortunately, there was only one sample from the B-1 formation and correlation of the alteration of wettability and aging time was not possible. However, it was sufficient to determine the effect of wettability on relative permeability when the mineralogy, pore size distribution, and fluid properties were kept constant. After the third group of experiments had been completed, sample 74 was re-extracted with toluene for three weeks and the wettability of the sample was checked by spontaneous water imbibition. After five days, the amount of water imbibed was 1.2 cm3 and the test was finished. This value was very similar to those obtained during the first two measurements, meaning that the alteration of wettability by aging is a reversible process and it is possible to re-establish the initial wettability condition by way of a successful cleaning. Shortly, although aging reduced the wettability of the water-wet samples, intermediatewet samples were not affected by this process. However, this was not an unusual case, because aging is already known as the most useful method to reduce waterwetness and researchers have used it to alter the wettability of core samples from strongly water-wet to different degrees of wettability.4,6,7,15-17 However, there was insufficient information about the effects of aging on intermediate-wet core samples. Tang and Morrow17 reported that water-wetness was decreased by increased salinity. In this study, similar results were obtained for the B-1 samples. The wettability indices of almost all samples (except for sample

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Table 4. Wettability Test Resultsa (Measurement II) plug number

kw (md)

ko @ Swi (md)

kw @ Sor (md)

Swi (%)

Sor (%)

Iw

Io

IAH

51 52 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 71 72 73 74 75

0.94 15.04 1.09 3.67 1.13 1.30 5.72 2.23 6.63 2.84 2.53 1.13 2.13 6.24 6.02 0.06 18.36 7.94 5.98 6.61 17.63 4.05 18.86

1.44 14.97 1.19 3.51 1.10 1.70 5.54 3.52 5.86 2.76 2.25 1.72 1.18 4.93 3.30 0.10 38.23 7.13 9.49 5.59 20.62 3.63 16.42

0.58 6.48 0.34 0.90 0.49 0.25 2.31 1.11 1.55 0.75 0.74 0.35 0.55 1.11 2.08 0.01 6.34 2.30 0.99 0.36 1.82 0.23 1.84

57.30 33.21 27.65 20.30 31.82 44.08 36.39 56.79 26.39 42.24 23.89 42.60 25.20 36.05 35.90 66.03 52.81 33.33 39.98 12.32 14.72 19.87 11.62

15.15 25.05 24.84 39.23 25.16 21.44 31.14 24.38 26.88 27.08 39.23 16.56 25.61 22.05 26.44 7.90 13.53 21.31 27.11 55.56 47.90 50.33 55.08

0.10 0.01 0.01 0.05 0.02 0.03 0.00 0.02 0.03 0.00 0.02 0.05 0.01 0.00 0.04 0.03 0.01 0.02 0.38 0.58 0.56 0.67 0.78

0.05 0.01 0.05 0.00 0.00 0.01 0.04 0.05 0.00 0.02 0.04 0.05 0.07 0.02 0.01 0.09 0.09 0.01 0.00 0.00 0.00 0.00 0.00

0.05 0.00 -0.03 0.05 0.02 0.01 -0.04 -0.04 0.03 -0.02 -0.02 0.00 -0.06 -0.02 0.03 -0.06 -0.08 0.01 0.38 0.58 0.56 0.67 0.78

resultb IW IW IW IW IW IW IW IW IW IW IW IW IW IW IW IW IW IW WW WW WW WW WW

a Abbreviations used in table are as follows: k , permeability of water; k @ S , permeability of oil at initial water saturation; k @ S , w o wi w or permeability of water at initial oil saturation; Swi, initial water saturation; Sor, initial oil saturation; Iw, wettability index for water; Io, b wettability index for oil; and IAH, Amott-Harvey wettability index. IW, intermediate-wet; WW, water-wet.

Figure 6. Variation of the endpoint relative permeabilities, with respect to the wettability characteristics of the core sample.

54) were reduced to different degrees. However, the changes that occurred on M-1 samples (samples 5266) were not considerable, as shown in Figure 9 for intermediate-wet samples. The alterations that occurred in B-1 samples were more meaningful. However, it was very difficult to state that it was caused only by a change in salinity. It was important to note that, as it happened in the previous study, a significant amount of wettability reductions occurred only in the water-wet samples. The IAH values were increased for samples 73 and 75 for water-wet conditions, from 0.44 to 0.60 with increasing brine salinity. The effect of changes in saturation procedure on wettability is shown in Figure 10. The effect of saturation procedure did not cause important changes in the wettability of the core samples. For core plugs that have been aged with decane or other hydrocarbons as the oil, the wettability changes

are sensitive to the aging period. Wettability is shown to be dependent on the choice of crude oil, brine composition, initial water saturation, and aging temperature. In contrast to the results obtained with crude oil, wettability changes induced by mineral oil were insensitive to brine composition (according to Jadhunandan and Morrow15). The dependence of the wettability index on the initial water saturation for mineral oil showed the same qualitative trend as that for crude oil; however, the extent of wettability change induced by mineral oil was always less. Insensitivity of the mineral oil, in regard to brine composition, was also observed for spontaneous imbibition rate measurements. It is documented in the literature that asphaltenes and resins are the most active fractions of the crude oil, in regard to wettability alterations of the mineral surfaces.



Figure 7. Comparison of the Amott-Harvey wettability index (IAH) values obtained from the first and secund group of experiments.

Figure 8. Effect of the variation of aging period on the wettability of the core samples.

Graue et al.24 aged the core plugs in refined and crude oils, such as paraffins, white mineral oil, and three crude oils. For unaged cores, the imbibition rate evidently decreased as the oil viscosity for the refined oils increased. The crude oil had the lowest imbibition rate, despite not being the most viscous oil. This behavior is believed to be either an effect of aging or an artifact of wax formation, because the imbibition was performed at room temperature. When the aged crude oil was exchanged by fresh crude oil or decane after aging but before imbibition, the results exhibited different but consistent Amott indices. Different crude oils and different refined oils gave different effects, with respect to changes of the wettability in different porous media. 3.2. Relative Permeability Studies. Eight steadystate relative permeability tests were conducted on (24) Graue, A.; Viksund, B. G.; Eilertsen, T.; Moe, R. Systematic Wettability Alteration by Aging Sandstone and Carbonate Rock in Crude Oil. J. Pet. Sci. Eng. 1999, 24, 85-97.

seven core samples from both formations. The relative permeability of sample 74 was measured two times, for two different wettability conditions. During the core flood studies, the volume of the displacing phase was extended up to 65 PVs to obtain the endpoint relative permeability as correctly as possible. Although the porosity and permeability of the samples were in the range of 13%-23% and 3-83 md, respectively, neither the relative permeability curves of the oil nor water of the M-1 formation plugs varied too greatly, as shown in Figure 11. This behavior could only be explained by the wettability of the system because the wettability indices of the samples were very similar to each other. It was previously noted that wettability is one of the most important factors that affects the relative permeability.2,8,13,19,20 The results of the relative permeability tests conducted on the B-1 samples were quite different. Although the petrophysical properties of the samples did

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Karabakal and Bagci

Figure 9. Effect of the variation of brine salinity on the wettability of the core samples.

Figure 10. Effect of changes in saturation procedure on wettability.

not vary significantly, the relative permeabilities of both water and oil of the samples showed differences. The effect of wettability was greater, especially in relative permeability curves of the oil. Variation of the relative permeability of the oil, with respect to the measured wettability indices, is shown in Figure 12. Decreasing water-wetness decreased the value of the endpoint relative permeability of the oil (kro at Swi) significantly. The maximum permeability value was obtained for the sample that had the highest wettability index. The permeability was low for the intermediate-wet sample, as reported by Dandina et al.25 Note that, for the waterwet samples, endpoint effective permeability values of the oil are greater than the absolute brine permeability of the medium. It was an unexpected result. However, (25) Dandina, N. R.; Marcel, G.; Sayegh, S. G. The Influence of Reservoir Wettability on Waterflood and Miscible Flood Performance. J. Can. Pet. Technol. 1992, 31 (3), 47-55.

McPhee and Arthur26 reported that this parameter might attain values up to 2.4 times of the absolute permeability in strongly water-wet rocks. They explained this condition as a lubrication effect, in which the presence of water in a strongly water-wet rock acts as a lubricant, easing the flow of oil through the pores, and this effect should be considered while evaluating the relative permeability data. They also stated that the effect of lubrication is greater for the nonwetting phase. During this study, the relative permeability of sample 74 was measured two times, for two different wettability conditions. Results of the measurements to see the effect of wettability on relative permeability were very good, whereas the other parameters (such as pore size dis(26) McPhee, C. A.; Arthur, K. G. Relative Permeability Measurements: An Inter-laboratory Comparison. Presented at the SPE European Petroleum Conference, London, October 25-27, 1994. (SPE Paper No. 28826.)



Figure 11. Relative permeability curves of the M-1 samples.

Figure 12. Relative permeabilitity curves of the oil for B-1 samples.

tribution, mineralogy, viscosity ratio, and salinity) were kept constant, as shown in Figure 13. When the relative permeability curves were based on the absolute brine permeability, as shown in Figure 13a, a decrease in the relative permeability of the oil with decreasing waterwetness could be seen easily. For all the water saturation values, the relative permeability of the oil of the sample was higher than that obtained when the sample was water-wet (see the work of Craig,13 Owens and Archer,19 and Donaldson and Thomas20), meaning that oil flowed more easily in a water-wet medium. To see the influence of wettability on the relative permeability of the water, the curves based on effective oil permeability at initial water saturation, as shown in Figure 13b, were more helpful. The relative permeability of the water of the sample was lower when the system was

water-wet, meaning that increasing the water-wetness reduced the flow of the water. Under water-wet conditions, the relative permeability curves for sample 74 had a cross-over point of >50% water saturation and the endpoint relative permeability of the water was

Determination of Wettability and Its Effect on Waterflood Performance

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