- Email: [email protected]
Factors affecting contact-angle measurement of reservoir rocks
Journal of Petroleum Science and Engineering 44 (2004) 193 – 203 www.elsevier.com/locate/petrol
Factors affecting contact-angle measurement of reservoir rocks Shedid A. Shedid *, Mamdouh T. Ghannam Chemical and Petroleum Engineering, College of Engineering, United Arab Emirates University, P.O. Box 17555, Al-Ain, United Arab Emirates Received 11 December 2003; accepted 7 April 2004
Abstract Much attention has been devoted to the study of the improved oil recovery (IOR) method(s). However, it still remains a challenge to evaluate the reservoir wettability quantitatively using actual core samples. Contact angle is considered as one of the most common methods to measure the preferential affinity of reservoir rocks. The main objectives of this study are to investigate the influence of droplet volume, brine salinity, liquid saturated rocks, oil acid number, and temperature on rock wettability of carbonate reservoir rock using sessile droplet method. Sixteen runs were undertaken using oil droplet volumes of 10, 15, 20, and 25 ml with different brine salinities of zero, 50,000, 100,000, and 150,000 ppm of NaCl, respectively. This has been done to study the effect of droplet volume and salinity on contact angle. In three runs, different crude oils having acid numbers of 0.374, 0.561, and 0.986 mg KOH/g samples were performed to investigate the influence of acid number on the contact angle. Three runs were carried out using brine, crude oil, and polymer solutions to study the effect of liquid-type saturated rock on contact angle. Finally, two runs were used to study the effect of temperature on contact angle. In all experiments, actual rock and crude oil samples were used. Results indicated that there is a specific droplet volume attained at critical water salinity. This critical water salinity is defined as the salinity at which the oil droplet volume has no effect on contact angle. Rock wettability decreases below the critical salinity and increases above it, depending on the droplet volume. The attained results indicate that liquid saturated rock has an important role on measured values of contact angle. Results also show that an increase in acid number of the crude oil decreases the contact angle. Therefore, carbonate oil reservoirs containing oils of low acid number are expected to be more oil-wet than that ones containing oils of higher acid number. The increase of temperature and bath liquid viscosity reduced the measured contact angle. The results of this study developed a new concept of critical salinity and provided better understanding of some factors affecting wettability measurements using contact-angle technique. D 2004 Elsevier B.V. All rights reserved. Keywords: Wettability; Salinity; Reservoir rock; Contact angle
1. Introduction and literature review Wettability of a solid surface by a liquid is a significant parameter for the displacement of one liquid by another. Wettability of a reservoir rock is used to define the distribution of oil in swept zones and the * Corresponding author. Tel.: +971-37-705-1636. E-mail address: [email protected] (S.A. Shedid). 0920-4105/$ - see front matter D 2004 Elsevier B.V. All rights reserved. doi:10.1016/j.petrol.2004.04.002
distribution of by-passed oil. Wettability of reservoir rock is therefore fundamental to petroleum production and its efficient management. Proper consideration of rock wettability in the oil recovery engineering improves actual reservoir production performance under immiscible displacement processes and enables projects to be more successful economically. Craig (1971) defined wettability as a tendency of a fluid to spread on or adhere to a solid surface in the
194
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
presence of another immiscible fluid. Tiab and Donaldson (1999) defined wettability as the term describing the relative adhesion of two fluids to a solid surface. They pointed out that for a porous medium containing two or more immiscible fluids, wettability is a measure of the preferential tendency of one of the fluids to wet (spread or adhere) to the solid surface. Different methods have been used to measure the surface wettability of a system (Anderson, 1986a,b; Tiab and Donaldson, 1999; Li and Horne, 2003). These methods are classified into two main categories: (1) Quantitative methods including contact angle, Amott wettability index (AWJ), USBM (U.S. Bureau of Mines) wettability index, and Li and Horne method. (2) Qualitative methods including imbibition rate, flotation, microscopic examination, capillary pressure curves, reservoir logs, permeability/ saturation relationship, nuclear magnetic resonance, and dye adsorption. The contact-angle method (also called sessile droplet method) is commonly used to measure the wetting properties of the solid surface with respect to two immiscible fluids. Treiber et al. (1972) indicated that a smooth, homogenous surface is necessary to apply the sessile droplet method to produce direct-angle measurement of surface wettability. They mentioned that polished quartz and calcite plates are commonly used for this purpose. Orkoula et al. (1999) studied wettability of a calcium carbonate layer deposited on microscope glass slides using the contact-angle technique. The study indicated that an increase in temperature and/or the deposited amount of calcium carbonate caused increase in wettability (reduction in contact angle) of calcium carbonate. Anderson (1986a,b) indicated that in water-wet rock, water has the tendency to fill small pores contacting the major part of the rock surface. Similarly, in oil-wet rocks, oil tends to preferentially occupy small pores and contact the majority of the rock surface. Therefore, the nonwetting fluid is expected to occupy the centers of large pores while wetting phase occupies the small pores to contact the major part of the rock
surface at the equilibrium condition of the system. The second part of wettability literature survey Anderson (1986a,b) indicated that the contact angle is the best method to measure wettability if pure fluids and artificial cores are used. The contact-angle method suffers from some drawbacks when actual crude oils and core samples are used. The current study summarized the problems of applying the contact-angle technique using actual reservoir rock samples and fluids as follows: (1) the contact angle does not consider the effects of roughness, heterogeneity, and complex reservoir rock geometry; (2) the contact-angle measurements does not take into account the heterogeneity of rock surface; and (3) no information can be attained about the increase or decrease in the attached organic coatings of the reservoir rocks. De Silva and Dawe (2003) studied the effects of heterogeneity on reservoir wettability and permeability of an immiscible displacement processes. The study indicated that wettability heterogeneity of an oil reservoir has a severe effect on oil displacement through porous medium by water flood. They indicated that wettability is an important parameter used to better predict production performance, and allow for the proper placement of injection and production wells. Zekri et al. (2003) investigated the effect of salinity on contact angle using four different concentrations of NaCl, 0, 1000, 10,000, and 50,000 ppm. The study concluded that salinity has an effect on the contact angle and that no optimum salinity exists for the used system. The study did not use higher salinity to confirm the attained conclusion. Therefore, in this current study, we used salinities above 50,000. In the present work, we have applied the sessile droplet method to study the effect of oil droplet volume, water salinity, type of liquid saturating rock, crude oil acid number, and temperature on the rock wettability using contact angle of carbonate rocks.
2. Experimental apparatus and methodology 2.1. Chemical-composition determination of rock samples Chemical composition of four core samples was obtained using both titration and gravimetric methods.
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
The chemical composition determination was obtained according to the following. Calcium was determined by using ethylenediaminetetraacetic acid (EDTA) titration (Vogel, 1970). In this method, a sample of about 0.40 g was placed in 400-ml beaker. Then, 5 –10 droplets of 1:1 hydrochloric acid (HCl) is added. Fifty millimeter of the resultant solution is standardized with sodium hydroxide (NaOH) solution of pH 6. The produced solution is transferred to a 50ml beaker, and 10 ml of pH 10 (NH4Cl + NH4OH) ammonia buffer is added. The solution is titrated with EDTA solution using Eriochrome Black Tea (EBT) as an indicator. The sulfur content was determined by precipitation process, as barium sulfate (Vogel, 1970). The result indicated the used core sample containing 99.8 wt.% of calcium carbonate to have zero sulfur content. 2.2. Apparatus and methodology Actual crude oil ‘‘B’’, United Arab Emirates, was used to investigate the effects of droplet volume, salinity, type of liquid saturating rock, and temperature on contact angle. The applied experimental procedure is described as follows: 1. Five identical carbonate rock samples (3.5 cm in diameter and 7.5 cm in height) are cut from Hafiet Mountain, Al Ain City, UAE, which has the same outcrop of one of the major oil fields in the United Arab Emirates.
195
2. Every core sample was cleaned by injecting 10 pv toluene to dissolve deposits in situ, followed by 10 pv of brine of 100,000-ppm salinity, and then 10 pv of actual crude oil. The cores were then aged for 40 days at 65 jC similar to reservoir temperature to restore the rock wettability as recommended by different researchers (Anderson, 1986a,b; Donaldson et al., 1987; Donaldson and Siddiqui, 1987). 3. Core samples of similar porosity and permeability were cut into five disks of 3.5-cm diameter and 1.5-cm thickness and used to investigate the effect of droplet volume and salinity on contact angle. The crude oil from Buhasa oil field, which has an acid number of 0.374 mg KOH/g and 38.68j API used in this experiment. 4. This carbonate disk (3.5-cm diameter and 1.5-cm thickness) was suspended horizontally in specified water salinity and a droplet of oil was placed at the bottom of the rock disk. 5. To study the effect of type of liquid-saturating rock on contact angle, the rock samples were saturated with brine (100,000 ppm), polyacrylamide polymer (AF-1235, 1000 ppm concentration) and ‘‘S’’ oil, respectively, and immersed in water bath with 100,000-ppm salinity. 6. To study the effect of oil acid number on contact angle, two actual crude oils from ‘‘S – C’’ (acid number = 0.986 mg KOH/g) and ‘‘S – D’’ (acid number = 0.561 mg KOH/g) fields with ‘‘B’’ crude oil (acid number = 0.347 mg
Fig. 1. Schematic diagram of apparatus used to measure the contact angle.
196
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
KOH/g) were used to provide different oil droplets of the same volume (15 ml) at the bottom of the carbonate disks saturated with 100,000 ppm NaCl solutions. 7. A high-resolution color video camera from SONY (DCR-PC100E) was used to record the crude oil droplet behavior over elapsed time. A 200-W light source was placed on the opposite side of the tank. All measurements were recorded at room temperature of 23 jC, except for two other different temperatures of 38 and 13 jC. A schematic diagram of the used experimental apparatus is shown in Fig. 1. 8. The variation of the contact angle as a function of elapsed time for different oil droplet volumes, water salinities, oil acid numbers, and saturating liquids was monitored by using 11 photographs over 120-min intervals for each performed run. The final stabilized contact angle after 120 min was considered and used as the valid wettability measurement. Therefore, every run provides only a single value of the contact angle. 9. Measurements and analysis of experimental data were completed using SigmaScan Pro 5.0 software from SPSS Science software (1998). The computerized image analysis system was used to accurately measure the contact angle. The system consists of a high-resolution video camera, an image processor, a Pentium PC, a high-resolution image monitor, and a highresolution text monitor. 10. The attained photograph for the oil droplet at the bottom of the carbonate disk was used to produce a microphotograph, which is used to determine the contact angle on the PC monitor using the highresolution image and text monitors.
3. Results and discussion Actual rock samples with actual crude oils were used to perform this study. Twenty-two runs were undertaken to investigate the influence of oil droplet volume, brine salinity, liquid saturating rock, oil acid number, and temperature on contact angle. These runs are classified in Table 1. The carbonate disks used are cut from five rock samples having porosity range from 18.45% to 19.23%
Table 1 Summary of conducted runs Run Liquid no. saturating rock
Salinity of Droplet Crude oil Contact water bath volume acid number angle (j) (ppm NaCl) (ml) (mg KOH/g)
Effect of oil droplet volume and salinity of water bath 1 Water 0 10 0.374 2 Brine 50,000 10 0.374 3 Brine 100,000 10 0.374 4 Brine 150,000 10 0.374 5 Water 0 15 0.374 6 Brine 50,000 15 0.374 7 Brine 100,000 15 0.374 8 Brine 150,000 15 0.374 9 Water 0 20 0.374 10 Brine 50,000 20 0.374 11 Brine 100,000 20 0.374 12 Brine 150,000 20 0.374 13 Water 0 25 0.374 14 Brine 50,000 25 0.374 15 Brine 100,000 25 0.374 16 Brine 150,000 25 0.374 Effect of liquid saturating rock 11 Brine 100,000 17 Crude oil – 18 Polymer 1000
15 15 15
Effect of crude oil acid number 17 Buhasa oil 100,000 15 19
Arab D oil
100,000
15
20
Arab C oil
100,000
15
Effect of temperature 11 Oil 100,000 (T = 13 jC) 21 Oil 100,000 (T = 23 jC) 22 Oil 100,000 (T = 38 jC)
0.374 0.374 0.374
36.04 21.89 38.07 23.45 33.96 20.57 37.32 25.96 31.30 19.38 37.66 27.60 29.50 18.51 37.66 28.70
37.32 122.2 114.4
0.374 122.2 (B crude) 0.561 112.7 (S – D crude) 0.986 108.5 (S – C crude)
15
0.374
37.32
15
0.374
36.28
15
0.374
12.96
All rocks are carbonate disks (diameter of 3.0 cm and thickness of 1.5 cm).
and permeability range from 10.37 to 12.71 md, respectively. 3.1. Effects of oil droplet volume and saturating water salinity The investigation of the effects of oil droplet volume and water salinity on contact angle was achieved using
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
identical carbonate disks saturated with different water salinities of 0, 50,000, 100,000, and 150,000 ppm for each oil droplet volume of 10, 15, 20, and 25 ml, respectively. The variation of the contact angle with time was measured. An example of the acquired data is plotted in Fig. 2 for water salinity of 100,000 ppm at different oil volumes of 10, 15, 20, and 25 ml, respectively. An example of the attained photographs of the variation of oil droplet volume over different time intervals until stabilization is shown in Fig. 3 for droplet volume of 20 ml in 100,000 ppm solution. The stabilized values of contact angles of this group of experiments were plotted vs. different water salinities in Fig. 4. This figure depicts the results of the 16 runs to provide a complete picture on the effects of water salinity and droplet volume on contact angle. Fig. 4 reveals important features such as (1) there is a systematic effect of water salinity on contact angle for different oil droplet volumes; (2) there are two inflection points for each droplet volume depending on the used water salinity; (3) contact angle decreases with the droplet volume as the salinity increases in the range of 0 to 100,000 ppm while the contact angle increases as the droplet volume increase in the range of 100,000 to 150,000 ppm; and (4) the water salinity has a characteristic point (at 100,000 ppm NaCl salinity) at which the drop volume has no effect on contact angle. Fig. 4 shows a significant reduction in contact angle for all tested droplet volumes with the increase
197
of water salinity over the range of 0 –50,000 ppm. This reduction in contact angle can be attributed to the effect of salt on the interfacial tension between crude oil – aqueous phases. The presence of salts in the aqueous phase has strong ability to increase the accumulation of the surface-active species; these are available in crude oil, at the crude oil –aqueous phase interface, and thereby reduce the interfacial tension and contact angle (Standal et al., 1999). In the salinity concentration range from 50,000 to 100,000 ppm, the repulsive electrostatic double-layer forces and repulsive hydration forces increase to avoid the spreading of crude oil. This influence causes a significant increase in contact angle over the range of NaCl concentration of 50,000 to 100,000 ppm. When salinity concentration increases to exceed 100,000 ppm, it prevents the surface-active material from dissolving into the aqueous phase. Instead, the surface-active material will adsorb onto the solid surface, which will enhance the oil-wetting behavior on the solid surface. 3.2. Effect of liquid saturating rock Three runs (runs No. 11, 17, and 18) were conducted using three different liquids saturating three similar carbonate rock disks immersed in 100,000 ppm salt water bath. The liquids used were brine of 100,000 ppm, polymer of 1000 ppm, and the ‘‘S’’ crude oil. Three oil droplets of the same volume (15
Fig. 2. Variation of contact angle with time.
198
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
Fig. 3. Photos of sessile oil droplets in 100,000 ppm NaCl salinity over time.
ml) of ‘‘S’’ crude oil were placed at the bottom of the carbonate disks. The results are plotted in Fig. 5, which indicate that the liquid-type saturating reservoir rock has important effect on contact angle. 3.3. Effect of oil acid number Wettability of a reservoir rock can be defined as the ability of one fluid to spread over the solid substrate in presence of another immiscible fluid such as crude oil and water (Craig, 1971). Acid – base interaction is
considered one of the mechanisms in which crude oil constituents may modify the wetting properties of a rock surface (Buckley et al., 1998). Acid – base interactions influence surface charge at crude oil – brine solution and rock – brine solution interfaces (Cuiec, 1975), which alter the wettability characteristics of rock substrate. Several researchers have concluded that acids have the ability to adsorb onto mineral surfaces and modify the wetting characteristics of the surfaces (Thomas et al., 1993; Standal et al., 1999).
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
199
Fig. 4. Effects of droplet volume and water salinity on contact angle.
Three runs were conducted (runs No. 17, 19, and 20) using three different crude oils. These were ‘‘B’’, ‘‘S – D’’, and ‘‘S – C’’ having different acid numbers of 0.374, 0.561, and 0.986 mg KOH/g sample, respectively. The rock samples used were saturated with the same crude oil from which the droplet of oil was obtained and used at the bottom
of the rock. The salinity of water bath was 100,000 ppm and the droplet volume used was 15 ml. The droplet volume and water salinity of the bath are selected based on the results of the effects of droplet volume and salinity because the volume of 15 ml has no effect on contact angle at 100,000 ppm (critical salinity).
Fig. 5. Effect of liquid saturating rock on contact angle.
200
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
Fig. 6. Effect of acid number of crude oil on contact angle.
Fig. 6 shows a strong contact-angle reduction with the increase of crude oil acid number. The reported reduction in the crude oil contact angle may be referred to as the change in the solid surface charge promoting adsorption of undissociated acid to increase negative charge on the surface. As the acid dissociates, the interface of crude oil –brine solution becomes negatively charged. The repulsive forces between the interfaces of crude oil – brine and solid substrate – brine stabilize the thin film covering the solid substrate and the contact angle decreases. As the acid number increases, the negative charge increases at the crude
oil – brine solution, improving the repulsive force between the two surfaces of crude oil –brine solution and solid substrate –brine solution. Therefore, carbonate oil reservoirs containing oils of low acid numbers are expected to be more oil-wet. 3.4. Effect of bath liquid temperature Three runs of No. 11, 21, and 22 were performed using ‘‘B’’ crude oil at different bath temperature of 13, 23, and 38 jC to investigate the influence of temperature on measured contact angle. The results are
Fig. 7. Effect of temperature on contact angle.
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
201
Fig. 8. (A) Variation of contact angle with time for polymer as bath and liquid saturating rock. (B) Variation of contact angle with time for brine of 100,000 ppm NaCl as bath liquid and 1000 ppm polymer as a liquid saturating rock. (C) Effect of bath liquid on contact angle for different elapsed time intervals.
202
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
graphically presented in Fig. 7. This figure shows a gradual reduction in contact angle as the temperature increases from 13 to 23 jC. A sharp reduction is measured in contact angle when the temperature was increased from 23 to 38 jC. The reduction in contact angle may be attributed to the reduction in oil viscosity with the increase in temperature. 3.5. Effect of bath liquid viscosity Two runs were carried out using a polymer (AF1235 of concentration 1000 ppm) and saline water (100,000 ppm) as bath liquids, respectively, while similar core disks were saturated with polymer solution of 1000-ppm concentration. The attained results are shown in Fig. 8A and B, respectively. The contact angle increased when the polymer solution was used as a bath liquid, and it decreased when brine was used as a bath liquid. This attributed to the higher viscosity of the polymer solution (viscosity is measured to be 110 cP at 23 s 1 shear rate) in comparison to the brine viscosity (viscosity is 1.2 cP). Viscous bath liquid restricts the adhesion forces effect and limits the oil droplet expansion on the rock surface while less viscous solution such as the brine does not.
3.
4.
5.
6.
consequently affects the performance of waterflooding of the reservoir under development. The saturating liquid of carbonate reservoir rock has an important role on the wettability of this rock. Carbonate rocks saturated with brine are water-wet; rocks saturated with oil are oil-wet; while polymer solution in carbonate rocks provides more oil-wet rocks. The increase of the acid number of the crude oil makes the rock surface more water-wet. Therefore, carbonate oil reservoirs containing crude oils of high acid number are expected to be more water-wet than that ones containing oil of low acid number. The increase of temperature of bath liquid decreases the contact angle. Therefore, contact angle has to be measured at the reservoir temperature. The increase of bath liquid viscosity increases the contact angle.
Nomenclature AC acid number, mg KOH/g oil sample DV oil droplet volume, ml Swc critical water salinity, ppm NaCl Superscripts/subscripts C critical W water
4. Conclusions References The influences of oil droplet volume, water salinity, type of liquid saturating rock, oil acid number, temperature, and viscosity of bath liquid on contact angle have been experimentally investigated using the sessile droplet method. The conclusions of this work are as follows: 1. A new concept of critical salinity is developed at which the droplet volume has no effect on contact angle. Therefore, the contact angle has to be measured at this critical salinity to eliminate the droplet volume effect and to ensure reliable wettability measurement using the sessile droplet method. 2. Water salinity has systematic effects on contact angle depending on the used oil droplet volume. Displacing the injected water of different salinity into an oil reservoir changes the contact angle and
Anderson, W.G., 1986a. Wettability literature survey—Part 1: rock/ oil/brine interactions and the effects of core handling on wettability. J. Pet. Technol., 1125 – 1144 (October). Anderson, W.G., 1986b. Wettability literature survey—Part 2: wettability measurements. J. Pet. Technol., 1246 – 1262 (November). Buckley, J., Liu, Y., Monsterleet, S., 1998. Mechanisms of wetting alteration by crude oils. Soc. Pet. Eng., 54. Craig, F.F., 1971. The reservoir engineering aspects of waterflooding. Monograph Series, SPE, Richardson, TX, 3. Cuiec, L., 1975. Restoration of the natural state of core samples. SPE Paper 5634, Presented at the 1975 Annual Technical Conference and Exhibition, Dallas, Texas, Sept. 28 – Oct. 1. De Silva, J.M., Dawe, R.A., 2003. Effects of permeability and wettability heterogeneities on flow in porous media. SPE 81164, the SPE Latin American and Caribbean Petroleum Engineering Conference, Port-of-Spain, Trinidad, West Indies, 27 – 30 April. Donaldson, E.C., Civan, F., Alam, T.K., 1987. Relative permeabilities at simulated reservoir conditions. SPE 16970, the 62nd Annual Technical Conference, Dallas, TX, Sept. 27 – 30, 10. Donaldson, E.C., Siddiqui, T.K., 1987. Relationship between the
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203 Archie saturation exponent and wettability. SPE 16790, the 62nd Annual Technical Conference, Dallas, TX, Sept. 27 – 30, p. 8. Li, K., Horne, R.N., 2003. A wettability evaluation method for both gas – liquid – rock and liquid – liquid – rock systems. SPE 80233, SPE International Symposium on Oilfield Chemistry, Houston, Texas, U.S.A., 5 – 7 February. Orkoula, M.G., Koutsoukos, P.G., Robin, M., Vizika, O., Cuiec, L., 1999. Wettability of CaCO surfaces. J. Colloids Surf. A, Physicochem. Eng. Asp. 157, 333 – 340. SigmaScan Pro 5.0, 1998. User’s Guide, LEAD Technologies, Chicago, IL, USA. Standal, S., Haavik, J., Blokhus, A., 1999. Effect of polar organic components on wettability as studied by adsorption and contact angles. J. Pet. Sci. Eng. 24, 131 – 144.
203
Thomas, M., Clouse, A., Longo, J., 1993. Adsorption of organic compounds on carbonate minerals: 1. Model compounds and their influence on mineral wettability. Chem. Geol. 109, 201. Tiab, D., Donaldson, E.C., 1999. Petrophysics: theory and practice of measuring reservoir rock and fluid transport properties. Gulf Prof., 233 – 286. Treiber, L.E., Archer, D.L., Owens, W.W., 1972. A laboratory evaluation of the wettability of fifty oil-producing reservoirs. Soc. Pet. Eng. J. 12 (6), 531 – 540 (December). Vogel, A.I., 1970. Quantitative Inorganic Analysis, 4th ed. Longman Scientific Techniques, Part D, Chapter X, vol. 327. Zekri, A.Y., Ghanam, M., Al Mehedaideb, R.A., 2003. Carbonate rock wettability changes induced by microbial solution. SPE 80527, SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, Indonesia, September 9 – 11.
Factors affecting contact-angle measurement of reservoir rocks Shedid A. Shedid *, Mamdouh T. Ghannam Chemical and Petroleum Engineering, College of Engineering, United Arab Emirates University, P.O. Box 17555, Al-Ain, United Arab Emirates Received 11 December 2003; accepted 7 April 2004
Abstract Much attention has been devoted to the study of the improved oil recovery (IOR) method(s). However, it still remains a challenge to evaluate the reservoir wettability quantitatively using actual core samples. Contact angle is considered as one of the most common methods to measure the preferential affinity of reservoir rocks. The main objectives of this study are to investigate the influence of droplet volume, brine salinity, liquid saturated rocks, oil acid number, and temperature on rock wettability of carbonate reservoir rock using sessile droplet method. Sixteen runs were undertaken using oil droplet volumes of 10, 15, 20, and 25 ml with different brine salinities of zero, 50,000, 100,000, and 150,000 ppm of NaCl, respectively. This has been done to study the effect of droplet volume and salinity on contact angle. In three runs, different crude oils having acid numbers of 0.374, 0.561, and 0.986 mg KOH/g samples were performed to investigate the influence of acid number on the contact angle. Three runs were carried out using brine, crude oil, and polymer solutions to study the effect of liquid-type saturated rock on contact angle. Finally, two runs were used to study the effect of temperature on contact angle. In all experiments, actual rock and crude oil samples were used. Results indicated that there is a specific droplet volume attained at critical water salinity. This critical water salinity is defined as the salinity at which the oil droplet volume has no effect on contact angle. Rock wettability decreases below the critical salinity and increases above it, depending on the droplet volume. The attained results indicate that liquid saturated rock has an important role on measured values of contact angle. Results also show that an increase in acid number of the crude oil decreases the contact angle. Therefore, carbonate oil reservoirs containing oils of low acid number are expected to be more oil-wet than that ones containing oils of higher acid number. The increase of temperature and bath liquid viscosity reduced the measured contact angle. The results of this study developed a new concept of critical salinity and provided better understanding of some factors affecting wettability measurements using contact-angle technique. D 2004 Elsevier B.V. All rights reserved. Keywords: Wettability; Salinity; Reservoir rock; Contact angle
1. Introduction and literature review Wettability of a solid surface by a liquid is a significant parameter for the displacement of one liquid by another. Wettability of a reservoir rock is used to define the distribution of oil in swept zones and the * Corresponding author. Tel.: +971-37-705-1636. E-mail address: [email protected] (S.A. Shedid). 0920-4105/$ - see front matter D 2004 Elsevier B.V. All rights reserved. doi:10.1016/j.petrol.2004.04.002
distribution of by-passed oil. Wettability of reservoir rock is therefore fundamental to petroleum production and its efficient management. Proper consideration of rock wettability in the oil recovery engineering improves actual reservoir production performance under immiscible displacement processes and enables projects to be more successful economically. Craig (1971) defined wettability as a tendency of a fluid to spread on or adhere to a solid surface in the
194
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
presence of another immiscible fluid. Tiab and Donaldson (1999) defined wettability as the term describing the relative adhesion of two fluids to a solid surface. They pointed out that for a porous medium containing two or more immiscible fluids, wettability is a measure of the preferential tendency of one of the fluids to wet (spread or adhere) to the solid surface. Different methods have been used to measure the surface wettability of a system (Anderson, 1986a,b; Tiab and Donaldson, 1999; Li and Horne, 2003). These methods are classified into two main categories: (1) Quantitative methods including contact angle, Amott wettability index (AWJ), USBM (U.S. Bureau of Mines) wettability index, and Li and Horne method. (2) Qualitative methods including imbibition rate, flotation, microscopic examination, capillary pressure curves, reservoir logs, permeability/ saturation relationship, nuclear magnetic resonance, and dye adsorption. The contact-angle method (also called sessile droplet method) is commonly used to measure the wetting properties of the solid surface with respect to two immiscible fluids. Treiber et al. (1972) indicated that a smooth, homogenous surface is necessary to apply the sessile droplet method to produce direct-angle measurement of surface wettability. They mentioned that polished quartz and calcite plates are commonly used for this purpose. Orkoula et al. (1999) studied wettability of a calcium carbonate layer deposited on microscope glass slides using the contact-angle technique. The study indicated that an increase in temperature and/or the deposited amount of calcium carbonate caused increase in wettability (reduction in contact angle) of calcium carbonate. Anderson (1986a,b) indicated that in water-wet rock, water has the tendency to fill small pores contacting the major part of the rock surface. Similarly, in oil-wet rocks, oil tends to preferentially occupy small pores and contact the majority of the rock surface. Therefore, the nonwetting fluid is expected to occupy the centers of large pores while wetting phase occupies the small pores to contact the major part of the rock
surface at the equilibrium condition of the system. The second part of wettability literature survey Anderson (1986a,b) indicated that the contact angle is the best method to measure wettability if pure fluids and artificial cores are used. The contact-angle method suffers from some drawbacks when actual crude oils and core samples are used. The current study summarized the problems of applying the contact-angle technique using actual reservoir rock samples and fluids as follows: (1) the contact angle does not consider the effects of roughness, heterogeneity, and complex reservoir rock geometry; (2) the contact-angle measurements does not take into account the heterogeneity of rock surface; and (3) no information can be attained about the increase or decrease in the attached organic coatings of the reservoir rocks. De Silva and Dawe (2003) studied the effects of heterogeneity on reservoir wettability and permeability of an immiscible displacement processes. The study indicated that wettability heterogeneity of an oil reservoir has a severe effect on oil displacement through porous medium by water flood. They indicated that wettability is an important parameter used to better predict production performance, and allow for the proper placement of injection and production wells. Zekri et al. (2003) investigated the effect of salinity on contact angle using four different concentrations of NaCl, 0, 1000, 10,000, and 50,000 ppm. The study concluded that salinity has an effect on the contact angle and that no optimum salinity exists for the used system. The study did not use higher salinity to confirm the attained conclusion. Therefore, in this current study, we used salinities above 50,000. In the present work, we have applied the sessile droplet method to study the effect of oil droplet volume, water salinity, type of liquid saturating rock, crude oil acid number, and temperature on the rock wettability using contact angle of carbonate rocks.
2. Experimental apparatus and methodology 2.1. Chemical-composition determination of rock samples Chemical composition of four core samples was obtained using both titration and gravimetric methods.
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
The chemical composition determination was obtained according to the following. Calcium was determined by using ethylenediaminetetraacetic acid (EDTA) titration (Vogel, 1970). In this method, a sample of about 0.40 g was placed in 400-ml beaker. Then, 5 –10 droplets of 1:1 hydrochloric acid (HCl) is added. Fifty millimeter of the resultant solution is standardized with sodium hydroxide (NaOH) solution of pH 6. The produced solution is transferred to a 50ml beaker, and 10 ml of pH 10 (NH4Cl + NH4OH) ammonia buffer is added. The solution is titrated with EDTA solution using Eriochrome Black Tea (EBT) as an indicator. The sulfur content was determined by precipitation process, as barium sulfate (Vogel, 1970). The result indicated the used core sample containing 99.8 wt.% of calcium carbonate to have zero sulfur content. 2.2. Apparatus and methodology Actual crude oil ‘‘B’’, United Arab Emirates, was used to investigate the effects of droplet volume, salinity, type of liquid saturating rock, and temperature on contact angle. The applied experimental procedure is described as follows: 1. Five identical carbonate rock samples (3.5 cm in diameter and 7.5 cm in height) are cut from Hafiet Mountain, Al Ain City, UAE, which has the same outcrop of one of the major oil fields in the United Arab Emirates.
195
2. Every core sample was cleaned by injecting 10 pv toluene to dissolve deposits in situ, followed by 10 pv of brine of 100,000-ppm salinity, and then 10 pv of actual crude oil. The cores were then aged for 40 days at 65 jC similar to reservoir temperature to restore the rock wettability as recommended by different researchers (Anderson, 1986a,b; Donaldson et al., 1987; Donaldson and Siddiqui, 1987). 3. Core samples of similar porosity and permeability were cut into five disks of 3.5-cm diameter and 1.5-cm thickness and used to investigate the effect of droplet volume and salinity on contact angle. The crude oil from Buhasa oil field, which has an acid number of 0.374 mg KOH/g and 38.68j API used in this experiment. 4. This carbonate disk (3.5-cm diameter and 1.5-cm thickness) was suspended horizontally in specified water salinity and a droplet of oil was placed at the bottom of the rock disk. 5. To study the effect of type of liquid-saturating rock on contact angle, the rock samples were saturated with brine (100,000 ppm), polyacrylamide polymer (AF-1235, 1000 ppm concentration) and ‘‘S’’ oil, respectively, and immersed in water bath with 100,000-ppm salinity. 6. To study the effect of oil acid number on contact angle, two actual crude oils from ‘‘S – C’’ (acid number = 0.986 mg KOH/g) and ‘‘S – D’’ (acid number = 0.561 mg KOH/g) fields with ‘‘B’’ crude oil (acid number = 0.347 mg
Fig. 1. Schematic diagram of apparatus used to measure the contact angle.
196
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
KOH/g) were used to provide different oil droplets of the same volume (15 ml) at the bottom of the carbonate disks saturated with 100,000 ppm NaCl solutions. 7. A high-resolution color video camera from SONY (DCR-PC100E) was used to record the crude oil droplet behavior over elapsed time. A 200-W light source was placed on the opposite side of the tank. All measurements were recorded at room temperature of 23 jC, except for two other different temperatures of 38 and 13 jC. A schematic diagram of the used experimental apparatus is shown in Fig. 1. 8. The variation of the contact angle as a function of elapsed time for different oil droplet volumes, water salinities, oil acid numbers, and saturating liquids was monitored by using 11 photographs over 120-min intervals for each performed run. The final stabilized contact angle after 120 min was considered and used as the valid wettability measurement. Therefore, every run provides only a single value of the contact angle. 9. Measurements and analysis of experimental data were completed using SigmaScan Pro 5.0 software from SPSS Science software (1998). The computerized image analysis system was used to accurately measure the contact angle. The system consists of a high-resolution video camera, an image processor, a Pentium PC, a high-resolution image monitor, and a highresolution text monitor. 10. The attained photograph for the oil droplet at the bottom of the carbonate disk was used to produce a microphotograph, which is used to determine the contact angle on the PC monitor using the highresolution image and text monitors.
3. Results and discussion Actual rock samples with actual crude oils were used to perform this study. Twenty-two runs were undertaken to investigate the influence of oil droplet volume, brine salinity, liquid saturating rock, oil acid number, and temperature on contact angle. These runs are classified in Table 1. The carbonate disks used are cut from five rock samples having porosity range from 18.45% to 19.23%
Table 1 Summary of conducted runs Run Liquid no. saturating rock
Salinity of Droplet Crude oil Contact water bath volume acid number angle (j) (ppm NaCl) (ml) (mg KOH/g)
Effect of oil droplet volume and salinity of water bath 1 Water 0 10 0.374 2 Brine 50,000 10 0.374 3 Brine 100,000 10 0.374 4 Brine 150,000 10 0.374 5 Water 0 15 0.374 6 Brine 50,000 15 0.374 7 Brine 100,000 15 0.374 8 Brine 150,000 15 0.374 9 Water 0 20 0.374 10 Brine 50,000 20 0.374 11 Brine 100,000 20 0.374 12 Brine 150,000 20 0.374 13 Water 0 25 0.374 14 Brine 50,000 25 0.374 15 Brine 100,000 25 0.374 16 Brine 150,000 25 0.374 Effect of liquid saturating rock 11 Brine 100,000 17 Crude oil – 18 Polymer 1000
15 15 15
Effect of crude oil acid number 17 Buhasa oil 100,000 15 19
Arab D oil
100,000
15
20
Arab C oil
100,000
15
Effect of temperature 11 Oil 100,000 (T = 13 jC) 21 Oil 100,000 (T = 23 jC) 22 Oil 100,000 (T = 38 jC)
0.374 0.374 0.374
36.04 21.89 38.07 23.45 33.96 20.57 37.32 25.96 31.30 19.38 37.66 27.60 29.50 18.51 37.66 28.70
37.32 122.2 114.4
0.374 122.2 (B crude) 0.561 112.7 (S – D crude) 0.986 108.5 (S – C crude)
15
0.374
37.32
15
0.374
36.28
15
0.374
12.96
All rocks are carbonate disks (diameter of 3.0 cm and thickness of 1.5 cm).
and permeability range from 10.37 to 12.71 md, respectively. 3.1. Effects of oil droplet volume and saturating water salinity The investigation of the effects of oil droplet volume and water salinity on contact angle was achieved using
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
identical carbonate disks saturated with different water salinities of 0, 50,000, 100,000, and 150,000 ppm for each oil droplet volume of 10, 15, 20, and 25 ml, respectively. The variation of the contact angle with time was measured. An example of the acquired data is plotted in Fig. 2 for water salinity of 100,000 ppm at different oil volumes of 10, 15, 20, and 25 ml, respectively. An example of the attained photographs of the variation of oil droplet volume over different time intervals until stabilization is shown in Fig. 3 for droplet volume of 20 ml in 100,000 ppm solution. The stabilized values of contact angles of this group of experiments were plotted vs. different water salinities in Fig. 4. This figure depicts the results of the 16 runs to provide a complete picture on the effects of water salinity and droplet volume on contact angle. Fig. 4 reveals important features such as (1) there is a systematic effect of water salinity on contact angle for different oil droplet volumes; (2) there are two inflection points for each droplet volume depending on the used water salinity; (3) contact angle decreases with the droplet volume as the salinity increases in the range of 0 to 100,000 ppm while the contact angle increases as the droplet volume increase in the range of 100,000 to 150,000 ppm; and (4) the water salinity has a characteristic point (at 100,000 ppm NaCl salinity) at which the drop volume has no effect on contact angle. Fig. 4 shows a significant reduction in contact angle for all tested droplet volumes with the increase
197
of water salinity over the range of 0 –50,000 ppm. This reduction in contact angle can be attributed to the effect of salt on the interfacial tension between crude oil – aqueous phases. The presence of salts in the aqueous phase has strong ability to increase the accumulation of the surface-active species; these are available in crude oil, at the crude oil –aqueous phase interface, and thereby reduce the interfacial tension and contact angle (Standal et al., 1999). In the salinity concentration range from 50,000 to 100,000 ppm, the repulsive electrostatic double-layer forces and repulsive hydration forces increase to avoid the spreading of crude oil. This influence causes a significant increase in contact angle over the range of NaCl concentration of 50,000 to 100,000 ppm. When salinity concentration increases to exceed 100,000 ppm, it prevents the surface-active material from dissolving into the aqueous phase. Instead, the surface-active material will adsorb onto the solid surface, which will enhance the oil-wetting behavior on the solid surface. 3.2. Effect of liquid saturating rock Three runs (runs No. 11, 17, and 18) were conducted using three different liquids saturating three similar carbonate rock disks immersed in 100,000 ppm salt water bath. The liquids used were brine of 100,000 ppm, polymer of 1000 ppm, and the ‘‘S’’ crude oil. Three oil droplets of the same volume (15
Fig. 2. Variation of contact angle with time.
198
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
Fig. 3. Photos of sessile oil droplets in 100,000 ppm NaCl salinity over time.
ml) of ‘‘S’’ crude oil were placed at the bottom of the carbonate disks. The results are plotted in Fig. 5, which indicate that the liquid-type saturating reservoir rock has important effect on contact angle. 3.3. Effect of oil acid number Wettability of a reservoir rock can be defined as the ability of one fluid to spread over the solid substrate in presence of another immiscible fluid such as crude oil and water (Craig, 1971). Acid – base interaction is
considered one of the mechanisms in which crude oil constituents may modify the wetting properties of a rock surface (Buckley et al., 1998). Acid – base interactions influence surface charge at crude oil – brine solution and rock – brine solution interfaces (Cuiec, 1975), which alter the wettability characteristics of rock substrate. Several researchers have concluded that acids have the ability to adsorb onto mineral surfaces and modify the wetting characteristics of the surfaces (Thomas et al., 1993; Standal et al., 1999).
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
199
Fig. 4. Effects of droplet volume and water salinity on contact angle.
Three runs were conducted (runs No. 17, 19, and 20) using three different crude oils. These were ‘‘B’’, ‘‘S – D’’, and ‘‘S – C’’ having different acid numbers of 0.374, 0.561, and 0.986 mg KOH/g sample, respectively. The rock samples used were saturated with the same crude oil from which the droplet of oil was obtained and used at the bottom
of the rock. The salinity of water bath was 100,000 ppm and the droplet volume used was 15 ml. The droplet volume and water salinity of the bath are selected based on the results of the effects of droplet volume and salinity because the volume of 15 ml has no effect on contact angle at 100,000 ppm (critical salinity).
Fig. 5. Effect of liquid saturating rock on contact angle.
200
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
Fig. 6. Effect of acid number of crude oil on contact angle.
Fig. 6 shows a strong contact-angle reduction with the increase of crude oil acid number. The reported reduction in the crude oil contact angle may be referred to as the change in the solid surface charge promoting adsorption of undissociated acid to increase negative charge on the surface. As the acid dissociates, the interface of crude oil –brine solution becomes negatively charged. The repulsive forces between the interfaces of crude oil – brine and solid substrate – brine stabilize the thin film covering the solid substrate and the contact angle decreases. As the acid number increases, the negative charge increases at the crude
oil – brine solution, improving the repulsive force between the two surfaces of crude oil –brine solution and solid substrate –brine solution. Therefore, carbonate oil reservoirs containing oils of low acid numbers are expected to be more oil-wet. 3.4. Effect of bath liquid temperature Three runs of No. 11, 21, and 22 were performed using ‘‘B’’ crude oil at different bath temperature of 13, 23, and 38 jC to investigate the influence of temperature on measured contact angle. The results are
Fig. 7. Effect of temperature on contact angle.
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
201
Fig. 8. (A) Variation of contact angle with time for polymer as bath and liquid saturating rock. (B) Variation of contact angle with time for brine of 100,000 ppm NaCl as bath liquid and 1000 ppm polymer as a liquid saturating rock. (C) Effect of bath liquid on contact angle for different elapsed time intervals.
202
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203
graphically presented in Fig. 7. This figure shows a gradual reduction in contact angle as the temperature increases from 13 to 23 jC. A sharp reduction is measured in contact angle when the temperature was increased from 23 to 38 jC. The reduction in contact angle may be attributed to the reduction in oil viscosity with the increase in temperature. 3.5. Effect of bath liquid viscosity Two runs were carried out using a polymer (AF1235 of concentration 1000 ppm) and saline water (100,000 ppm) as bath liquids, respectively, while similar core disks were saturated with polymer solution of 1000-ppm concentration. The attained results are shown in Fig. 8A and B, respectively. The contact angle increased when the polymer solution was used as a bath liquid, and it decreased when brine was used as a bath liquid. This attributed to the higher viscosity of the polymer solution (viscosity is measured to be 110 cP at 23 s 1 shear rate) in comparison to the brine viscosity (viscosity is 1.2 cP). Viscous bath liquid restricts the adhesion forces effect and limits the oil droplet expansion on the rock surface while less viscous solution such as the brine does not.
3.
4.
5.
6.
consequently affects the performance of waterflooding of the reservoir under development. The saturating liquid of carbonate reservoir rock has an important role on the wettability of this rock. Carbonate rocks saturated with brine are water-wet; rocks saturated with oil are oil-wet; while polymer solution in carbonate rocks provides more oil-wet rocks. The increase of the acid number of the crude oil makes the rock surface more water-wet. Therefore, carbonate oil reservoirs containing crude oils of high acid number are expected to be more water-wet than that ones containing oil of low acid number. The increase of temperature of bath liquid decreases the contact angle. Therefore, contact angle has to be measured at the reservoir temperature. The increase of bath liquid viscosity increases the contact angle.
Nomenclature AC acid number, mg KOH/g oil sample DV oil droplet volume, ml Swc critical water salinity, ppm NaCl Superscripts/subscripts C critical W water
4. Conclusions References The influences of oil droplet volume, water salinity, type of liquid saturating rock, oil acid number, temperature, and viscosity of bath liquid on contact angle have been experimentally investigated using the sessile droplet method. The conclusions of this work are as follows: 1. A new concept of critical salinity is developed at which the droplet volume has no effect on contact angle. Therefore, the contact angle has to be measured at this critical salinity to eliminate the droplet volume effect and to ensure reliable wettability measurement using the sessile droplet method. 2. Water salinity has systematic effects on contact angle depending on the used oil droplet volume. Displacing the injected water of different salinity into an oil reservoir changes the contact angle and
Anderson, W.G., 1986a. Wettability literature survey—Part 1: rock/ oil/brine interactions and the effects of core handling on wettability. J. Pet. Technol., 1125 – 1144 (October). Anderson, W.G., 1986b. Wettability literature survey—Part 2: wettability measurements. J. Pet. Technol., 1246 – 1262 (November). Buckley, J., Liu, Y., Monsterleet, S., 1998. Mechanisms of wetting alteration by crude oils. Soc. Pet. Eng., 54. Craig, F.F., 1971. The reservoir engineering aspects of waterflooding. Monograph Series, SPE, Richardson, TX, 3. Cuiec, L., 1975. Restoration of the natural state of core samples. SPE Paper 5634, Presented at the 1975 Annual Technical Conference and Exhibition, Dallas, Texas, Sept. 28 – Oct. 1. De Silva, J.M., Dawe, R.A., 2003. Effects of permeability and wettability heterogeneities on flow in porous media. SPE 81164, the SPE Latin American and Caribbean Petroleum Engineering Conference, Port-of-Spain, Trinidad, West Indies, 27 – 30 April. Donaldson, E.C., Civan, F., Alam, T.K., 1987. Relative permeabilities at simulated reservoir conditions. SPE 16970, the 62nd Annual Technical Conference, Dallas, TX, Sept. 27 – 30, 10. Donaldson, E.C., Siddiqui, T.K., 1987. Relationship between the
S.A. Shedid, M.T. Ghannam / Journal of Petroleum Science and Engineering 44 (2004) 193–203 Archie saturation exponent and wettability. SPE 16790, the 62nd Annual Technical Conference, Dallas, TX, Sept. 27 – 30, p. 8. Li, K., Horne, R.N., 2003. A wettability evaluation method for both gas – liquid – rock and liquid – liquid – rock systems. SPE 80233, SPE International Symposium on Oilfield Chemistry, Houston, Texas, U.S.A., 5 – 7 February. Orkoula, M.G., Koutsoukos, P.G., Robin, M., Vizika, O., Cuiec, L., 1999. Wettability of CaCO surfaces. J. Colloids Surf. A, Physicochem. Eng. Asp. 157, 333 – 340. SigmaScan Pro 5.0, 1998. User’s Guide, LEAD Technologies, Chicago, IL, USA. Standal, S., Haavik, J., Blokhus, A., 1999. Effect of polar organic components on wettability as studied by adsorption and contact angles. J. Pet. Sci. Eng. 24, 131 – 144.
203
Thomas, M., Clouse, A., Longo, J., 1993. Adsorption of organic compounds on carbonate minerals: 1. Model compounds and their influence on mineral wettability. Chem. Geol. 109, 201. Tiab, D., Donaldson, E.C., 1999. Petrophysics: theory and practice of measuring reservoir rock and fluid transport properties. Gulf Prof., 233 – 286. Treiber, L.E., Archer, D.L., Owens, W.W., 1972. A laboratory evaluation of the wettability of fifty oil-producing reservoirs. Soc. Pet. Eng. J. 12 (6), 531 – 540 (December). Vogel, A.I., 1970. Quantitative Inorganic Analysis, 4th ed. Longman Scientific Techniques, Part D, Chapter X, vol. 327. Zekri, A.Y., Ghanam, M., Al Mehedaideb, R.A., 2003. Carbonate rock wettability changes induced by microbial solution. SPE 80527, SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, Indonesia, September 9 – 11.