SPE 168067

Effect of Brine Composition on Wettability Alteration of Carbonate Rocks in the Presence of Polar Compounds Muhammad Yousuf Jabbar, Hasan Salman Al-Hashim, KFUPM and Wael Abdallah, Schlumberger Middle East

Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Saudi Arabia section Annual Technical Symposium and Exhibition held in Khobar, Saudi Arabia, 19–22 May 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract The impact of brine salinity and its ionic composition on oil recovery on chalk formations and to less extent in carbonate reservoirs have been investigated extensively in recent years due to the potential of extra oil recovery. Surface wettability was suggested to be the main reason behind such extra recovery. This study investigates the wettability alteration of calcite crystal and carbonates outcrop rock surface aged in model oils of total acid number of 2 and then treated with different brines. Model oils were prepared by mixing toluene with short chain (Heptanoic acid) and long chain (Stearic acid) carboxylic acids and the investigated brines included range of salinity and the effect of individual ions such as SO4

2-, Ca2+ and Mg2+. The results of this study showed that the long chain fatty acid (stearic acid) strongly adsorbs onto the calcite surface from the oil phase compared to the short chain (heptanoic acid) as confirmed by the measured contact angles. Twice dilution of Arabian Gulf seawater has been found to be a less effecient EOR fluid for wettability alteration as compared to undiluted Arabian Gulf seawater. This was confirmed by the changes in the measured contact angles toward more water-wet for aged calcite in heptanoic acid model oil, aged calcite in stearic acid model oil and aged carbonate in stearic acid model oil systems. Also, it was observed that significant wettability alteration was observed for the twice diluted Arabian Gulf seawater with higher concentrations of SO4

2- and Mg2+. Introduction Enhanced oil recovery (EOR), also referred to tertiary oil recovery is gaining great attention in the last few years due to the fact that primary production in most reservoirs is declining and oil consumption still on the rise. The fact that even primary oil production does not recover more than 30-35% of initial oil in place makes EOR techniques attractive. EOR is generally achieved by injecting either miscible or immiscible fluids into the reservoir including CO2 injection, others are thermal treatment, chemical/surfactant injection, ASP (alkaline-surfactant-polymer) injection and recently low salinity water injection (which is also called dynamic water, smart water and low salinity water). The main parameters to influence here is pressure, viscosity reduction and interfacial tension reduction, which all contribute to the increase of capillary number and therefore enhance the amount of recoverable oil. Despite some technological challenges, harsh reservoir conditions (carbonate complexity, high-pressure, high-temperature, high-salinity), stringent regulations, and costly implementation that kept oil companies away from using EOR techniques, it is expected that EOR will grow in the next few years and perform extremely well in the world market. However, some challenges remain in understanding the best EOR technique to be used for specific reservoir and what controlling parameters one should focus on for designing the best production/recovery scenario. Carbonate oil reservoirs have neutral to oil-wet character. Based on an evaluation study for the wetting state of 161 carbonate reservoirs, it indicated that 15% were strongly oil-wet, 65% were oil-wet, 12% were in the intermediate class and 8% were water-wet (Chilingar and Yen, 1983). It is documented that close to 50% of the world proven petroleum reserves are located in carbonates, which usually show low oil recovery factor (less than 35%), mainly due to wettability and the fractured nature of these reservoirs’ which makes EOR a huge potential to boost oil recovery in carbonates (Strand, et al., 2006).

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Carbonate rocks are generally positively charged, acidic components such as carboxylic acids, R-COO- and asphaltenes are polar and negatively charged, therefore, most likely to adsorb on carbonates and alter its wettability. Several researchers have reported the ability of acids to adsorb on mineral surfaces and thereby alter the wetting properties of the surface to more oil-wet (Standnes, D. C. 2001; Thomas, et al., 1993; Standal, et al., 1999; Anderson, W. G., 1986; Hansen, et al., 2000; Tie and Morrow, 2005; Madsen, et al., 1996; Madsen and Lind, 1998). In other words, the wettability of hydrocarbon reservoirs depends on the specific interactions within the oil/rock/brine systems. As wettability of a reservoir is an important parameter affecting fluid distribution and flow of oil and water in the reservoir, the wetness of the reservoir need to be altered towards more water-wet in most cases to improve carbonate oil recovery. A new EOR method used on chalk formation showed the applicability of sea water injection to alter the reservoir wettability and enhanced its oil production (Strand, et al., 2006; Zhang and Austad, 2006; Zhang, et al., 2007). Water flooding for pressure maintenance is considered as secondary recovery method in reservoirs (Shariatpanahi, et al., 2010). Alteration of the injected water composition can presumably impact rock wettability and eventually provide additional oil recovery. This effect as suggested by several researchers is attributed to the ion exchange between the key ions such as (SO4

2–, Ca2+, Mg2+) present in seawater which releases some adsorbed carboxylic oil components from the rock surface, and consequently altering rock wettability to a more water-wet condition (Strand, et al., 2006; Zhang and Austad, 2006; Zhang, et al., 2007; Austad, et al., 2005; Austad, et al., 2008; Zhang and Austad, 2005). The potential use of low salinity water (also called Dynamic Water, Smart Water) as EOR technique has been found to be feasible as shown by different studies due to potential lower cost compared to chemical/surfactant EOR, more appealing in terms of infra structure investments and more environmental friendly. The great success in oil recovery by injection of seawater into mixed-wet Ekofisk chalk field is an example of successful low salinity seawater flooding (Sulak, R.M., 1991). Primary recovery factor of the Ekofisk field was estimated as 17% by pressure depletion; however, when sea water was injection in 1984, the recovery factor from the field reached to 50% (Sulak, R.M., 1991; Sulak, et al., 1990). Yousef et Al., (2011) reported 16-18% OOIP incremental in oil recovery by sequential flooding with twice and ten times dilution of Arabian Gulf Seawater following the seawater flooding. They used composite rock samples from Saudi Arabian carbonate reservoirs. Their experiments were carried out using live oil at a reservoir temperature of 100°C. Wettability alteration was reported as the key mechanism for the reported increment in oil recovery. Although these ions are suggested to be repossbile for surface wettability alteration and how it works, it is really not clear if that is the case on other carbonates or chalk since most experimentation are not done on surface analysis level. Several questions are still to be answered and certainly needs more insight and controlled research work to be conducted. To what level of alteration these ions can cause? what is the range of the injected water salinity needs to be met? Is it individual ion we are looking at, or a ratio as suggested by some researchers? How does reservoir temperature and pressure affect the recovery process using such technique? Do the type of polar spcies in crude oil and its acidity play a rule in the efficieny of wettability alteration or the recovery process? Too many question still unanswered. The aim of this study is to investigate the wettability alteration of calcite and carbonate surface aged in different carboxilc aicds using different water salinity and ionic content using contact angle measurements. Materials and Procedures Rocks: Calcite crystals (Iceland Spar) purchased from Ward’s Natural Science and carbonate rocks from Saudi Arab-D outcrop are used in this study for contact angle measurements. Rocks were cut within 15 x 6 x 2 mm and polished to minmim possible roughness to have smooth surfaces for contact angle measurements. The mineralogy of both surfaces was examined by X-ray diffraction technique (XRD). As shown in Figures 1, both samples are mainly made up of calcite (CaCO3).

Chemicals: Two different carboxylic acids are used in this study to represent the polar species of the reservoir crude oil. Heptanoic acid (CH3(CH2)5COOH) and stearic acid (CH3(CH2)16COOH ) are both supplied by Sigma Aldrich with purity higher than 99%, their chemical number is 100992537 and 100978191 respectively. Toluene supplied by Sigma Aldrich in HPLC grade (purity >99.8%).

Model oils were prepared with the carboxylic acid dissolved in toluene in the ratios shown in Table 1. The toluene used to prepare model oil was first equilibrated with deionized water for 24 hours. The equilibrated toluene and the required amount of carboxylic acid were then measured by weight and then mixed together. The model oil prepared with heptanoic/toluene (HA-MO) and stearic acid/toluene (SA-MO) with a total acid number (TAN) of 2.

SPE 168067 3

Figure 1 Surface mineralogy measurements of calcite crystal and outcrop carbonate using XRD.

Table 1 Makeup of model oil composition

Brines: The electrolyte concentrations of the formation Water (FW) and all used brines are listed in Table 2. The brine termed SWME is a synthetic Arabian Gulf Seawater, and SWME* is Arabian Gulf Seawater twice diluted. The synthetic Arabian Gulf Seawater (SWME) and the modified versions of the synthetic Arabian Gulf Seawater (SWME*, SWME*0S, SWME*2S, SWME*4S, SWME*0Ca, SWME*2Ca, SWME*4Ca, SWME*0Mg, SWME*2Mg and SWME*4Mg) were used in the contact angle measurements in this study. All brines were prepared by adding specific weight of the desired salts to deionized and deareated water. NaCl, CaCl2.2H2O and MgCl2.6H2O were supplied by LOBA CHEMIE while Na2SO4 was supplied by TECHNO PHARMCHEM.

Table 2 Ionic concentration of used brines

Contact angle measurements A First Ten Angstrom (FTA) sealed cell was used to measure contact angle for all studied systems. The cell capacity is 22 cc with a 25 mm view port window to allow light passage. The cell is mounted on adjustable jacket in front of optical system from KRÜSS (DSA100) and the overall setup sits on top of a vibration-free table for accurate measurements of contact angle. The rock sample is placed inside a cell which is sealed with viton o-rings and rated to 100 psi and operates up to 100°C. An inverted stainless steel needle with tip diameter of 0.41 mm was used to make a drop of model oil on the rock surface and with brine bulk solution. A Dell desktop computer was used to acquire the digital image of the oil drop and perform the subsequent drop image analysis, digitization, and computation; DSA1 v1.9 drop shape analyzer from KRÜSS was used to determine the contact angles from the shape of sessile drops. Two replicates were performed for each combination of oil and water phase system. Contact angle measurements were also acquired for rock/brine/air systems. All measurements were run at atmospheric conditions.

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Calcite Carbonate

Components Mass (gms) Components Mass (gms)Toluene 348.36 Toluene 120.10Heptanoic Acid 1.63 Stearic Acid 1.25

FW SWME SWME* SWME*0S SWME*2S SWME*4S SWME*0Ca SWME*2Ca SWME*4Ca SWME*0Mg SWME*2Mg SWME*4Mg

mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l mg/l

Na+ 62,000 18,043 9,022 9,800 8,550 6,850 9,022 9,022 8,400 11,200 7,550 4,400

Ca++ 23,314 652 326 326 326 326 0 652 1,304 326 326 326

Mg++ 1,268 2,159 1,080 1,080 1,080 1,080 1,080 1,080 1,080 0 2,159 4,318

Cl‐ 120,000 31,808 15,904 18,000 13,500 9,500 16,550 14,900 13,500 18,400 12,000 4,300

SO4‐‐ 250 4,450 2,225 0 4,450 8,900 2,225 2,225 2,225 2,225 2,225 2,225

HCO3‐ 79 173 87 87 87 87 87 87 87 87 87 87

TDS 206,911 57,285 28,643 29,292 27,992 26,742 28,963 27,965 26,595 32,238 24,347 15,656

Ionic Strength 4.31 1.15 0.57 0.57 0.57 0.57 0.57 0.57 0.57 0.57 0.57 0.57

Ions

4 SPE 168067

Initially and for SA-MO aged calcite, three different scenarios of sample preparation were evaluated in this work as demonstrated in Figure 2. In approach 1 and 2, surfaces were initially saturated in formation water for two hours and then rinsed with deionized water and allowed to dry and then aged in model oil for five days at 65°C. In approach 1, the sample was treated with the proper brine at 90°C for five days, while in approach 3; the sample was rinsed with toluene before treatement with brines at same conditions. In approach 2, sample surface was not saturated in formation water, it ws directly aged with a model oil and then treated with the proper brine without tolune rinse. In all approaches, samples were rinsed with deionized water after brines treatment and before contact angle measurements.

Figure 2 Flow Chart demonstrating the three different approaches used in surface treatment

pH measurements The pH-measurements were performed by a ROSS combination pH electrode (0–14 pH, glass body, model no. 8102) connected to an OAKTON ACORN pH-meter. Sodium hydroxide and hydrochloric acid were used to obtain the desired pH value. The accuracy of the measured pH is reported within ± 0.05. The pH of used brine was recorded before treatement and after surface treatment at room temperature. Results and Discussion Effect of short and long chain fatty acid on wettability alteration of calcite surfaces During the last two decades, the importance of acidic components in the crude oil has been emphasized on the wettability alteration of reservoir rocks towards oil-wet conditions (Standnes, D. C., 2001). Carboxylic acids consist of one or more carboxyl groups attached to a hydrocarbon chain of various length. The carboxyl group is polar, negatively charged, therefore, it is believed the carboxyl groups in crude oils adsorb onto the positively charged carbonate rock surface and alter its initial water-wetting property to neutral or oil-wet. To mimic an acidic reservoir oil, carboxylic acids were dissolved in toluene to total acid number of 2 and then used to age the carbonate surface (calcite crystal and carbonate outcrop rocks).

Approach 1 (A1)

Approach 2 (A2)

Approach 3 (A3)

Saturated in FW for 2 hours at 20°C.When removed from the FW, thesample was rinsed with DIW andallowed to dry until all the waterevaporates.

Aged in model oil for 5 days at 65°C. When removed from the oven, the sample was allowed to dry to remove the excess oil.

(A1) (A3)

(A1) (A2) (A3)

Rinsed with toluene for 2 seconds and left to dry.

The samples are treated with different brines in standing position for 5 days at 90°C. When removed from the brines the samples were rinsed with DIW and allowed to dry until all the water evaporates.

Contact angle measured on static sessile drops at a specific time interval.

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SPE 168067 5

In this study, we studied the effect of acid chain length on the surface wettability by measuring the contact angle through a droplet of water on calcite crystal surrounded by air. Figure 3 shows the contact angle measurements of untreated calcite crystal surface and treated calcite surfaces with heptanoic acid (C7H14O2) and stearic acid (C18H36O2). The measured contact angles of calcite surface treated with both carboxylic acids shows stearic acid alters the surface to become less water-wet than heptanoic acid. The emerged trend agrees well with the “Traube’s rule” which states that long chain fatty acid such as stearic acid, strongly adsorbs onto the calcite surface compared to shorter chain fatty acid such as heptanoic acid, which adsorbs on the calcite surface to a lesser extent. The untreated calcite surface measured a contact angle of 62°, while calcite aged in heptanoic acid measured at 72° and for calcite aged in stearic acid at 87°.

Figure 3 Effect of carboxylic acid chain length on calcite wettability measured by water droplet in air at atmospheric

conditions

Milter (Milter, J., 1996) illustrated the importance of carboxylic acids by measuring the contact angle of a calcite crystal aged in the stearic acid dissolved in Dodecane and with only Dodecane. With stearic acid system, the calcite became oil-wet, while in pure Dodecane, it showed less alteration of calcite wettability towards oil-wet. Rezaei Gomari (Rezaei Gomari. K. A., 2009) reported adsorption of acidic components onto calcite is higher for stearic acid compared to oleic acid (C18H34O2). Anders (Anders, L., 2011) studied the importance of the chain length and showed stearic acid results in the highest contact angle compared to lauric acid (C12H24O2). Our results are also consistent with what has been published by Chukwudeme et al. (Chukwudeme and Hamouda, 2009) on the effect of polar components wettability alteration of calcite surfaces. Effect of Salinity, Ca2+, Mg2+ and SO4

2- ion concentration on wettability alteration of carbonate surfaces Wettability alteration of a carbonate can depend on parameters like brine salinity and concentration of the potential ions in the brine. Animportant factor for the wettability alteration and imbibition performance of modified sea water is the ability of this brine to interact with the adsorbed polar compounds on the carbonate surface and therefore, alter the surface properties to become more water-wet. This section discusses the effect of the ion type and concentration on wettability alteration of calcite crystal aged in heptanoic acid and stearic acid as well as carbonate outcrop aged in stearic acid. Effect of surface preparation Initially, aged calcite surface was prepared in three different approaches as demonstrated in Figure 2. In the first approach (A1), the surface is saturated with formation water, rinsed with deionized water and allowed to dry before aging in model oil and then dried naturally after. In the second approach (A2), the sample is aged directly in model oil without initial formation water saturation. In A1, several salt crystal particles were deposited on the surface when using salt saturated formation water; therefore, A2 was followed to avoid such salt deposition. The third approach (A3), follows (A1) approach exactly with one additional step which is rinsing the surface with toluene after aging in model oil to remove any lose adsorbed particles. A system of aged calcite prepared using the three different approaches was treated with SWME and SWME*and then contact

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angle was measured before and after treatment using a drop of deionized water in air. The salinity of SWME is approximately 57 kppm and SWME* (twice diluted) is approximately 28 kppm. Hence, the concentration of the ions in SWME* is half of that present in SWME. Aged calcite treated by SWME showed a reduction of contact angle by 59% when approach A1 was used, a reduction of 81% when approach A2 was used and finally, a reduction of 65% when approach A3 was used. When treated with SWME*, a reduction of 77%, 58% and 76% in contact angle was measured for approach A1, A2, A3, respectively. The results for the systems prepared by approach A1 or A3 did not show much difference, but it was significantly different for approach A2 when the surface was not initially saturated with formation water. Despite the surface being more water-wet in approach A2, we do not believe this is the right approach to represent the reservoir rocks since they are initially saturated with formation water and it is our intention to mimic such conditions. One of A1 or A3 could be adapted since both showed close results, but again, we are trying to mimic reservoir conditions in terms of surface history exposure, we adopt approach A1 for the rest of this study with the need to remove any lose adsorbed species. At this point, it is worth mentioning and for all studied systems, a clear white film appeared on the surface after treatment with SWME and SWME*, it was not homogenous film but certainly visual by eye. The film characteristic and composition will be the subject of analysis in another study. Calcite aged in heptanoic acid model oil (HA-MO) system Twelve different calcite surfaces were initially aged in HA-MO using approach 1 (A1) and then treated with different brines at 90°C for 5 days. These brines reflect the effect of salinity and ionic content concentration of SO4

2-, Ca2+and Mg2+ ions. Figure 4 shows the measured contact angle for all studied systems using a drop of model oil (HA-MO) in brine bulk inside a sealed cell at atmospheric conditions. Initially, one aged calcite crystal was treated with deionized water for five days at 90°C to set a reference, the contact angle for such system was measured to be 45° (Figure 4). The effect of the salt concentration on surface wettability alteration is studied by treating the aged calcite crystal with SWME and SWME*. For the surface treated with SWME, the HA-MO droplet didn’t stick to the surface during contact angle measurement indicating that the surface is completely non-wetting (completely water-wet). The contact angle measured for calcite treated with SWME* was 36° as shown in Figure 4. Hence the reduction of ion concentration increases the contact angle from completely water-wet surface to 36°. However, when comparing DIW, SWME and SWME*, all brines have changed the calcite crystal towards more water-wet with SWME being most effective. To study the effect of SO4

2-, Ca2+ and Mg2+ ions, SWME* was used as the base brine to manipulate its ionic content. Three brines were prepared with twice the concentration of each ion in the base brine and named as SWME*2S, SWME*2Ca and SWME*2Mg, another three brines were prepared with four times the original concentration of each ions and named SWME*4S, SWME*4Ca and SWME*4Mg and the last three brines prepared for the study were without such ions in the base brine and named SWME*0S, SWME*0Ca and SWME*0Mg. Table 2 shows the ionic concentration of each prepared brine and the measured contact angle for each system and the results are plotted in Figure 4 and Figure 5. Table 2 also shows the ionic strength for each brine system used in this study which is 0.57 mol/l for all brines except SWME at 1.15 mol/l and FW at 4.31 mol/l. Figure 4 shows the importance of SO4

2- ions on the wettability alteration of the calcite crystal. The lowest contact angle is obtained when brine SWME*2S or SWME*4S are used. For brines SWME*2S and SWME*4S the contact angle measured were 23° and 21°, respectively. The second observation is that removing SO4

2- ions from the brine SWME*0S resulted in a contact angle of 44° which is close to the DIW treated sample at 45°. Rezaei Gomari (Rezaei Gomari, et al., 2006) showed that alteration of the wettability is not only due to possible reduction of the available active sites on the calcite surfaces but could also be due to a displacement process of various pre-adsorbed fatty acids including heptanoic acid; in agreement with the obtained results in this study. The effect of Ca2+ ions in the presence of SO4

2- and Mg2+ ions on calcite wettability alteration did not show significant alteration compared to base brine SWME*. For brine SWME*2Ca and SWME*4Ca, the contact angles measured are 36° and 31°, respectively. Hence, the brine SWME*4Ca resulted in a more water-wet surface. In the case where there was no calcium ions in brine (SWME*0Ca), contact angle measured at 64° which is higher than the DIW treated surface. The effect of Mg2+ ion in the presence of SO4

2- and Ca2+ ions was insignificant to whatever the ratio was including the brine without Mg2+ ions. Contact angles were measured at 42°, 43° and 43° for SWME*0Mg, SWME*2Mg and SWME*4Mg, respectively.

SPE 168067 7

Our results are in line with the observations made by Gupta (Gupta and Mohanty, 2008), the SO42- and Ca2+ ions are found to

change the contact angle to more water-wet conditions at the tested conditions. Higher SO42- ion concentration with constant

Ca2+and Mg2+ ions concentration causes the highest degree of wettability alteration. From the studied systems, SWME*4S gives the lowest contact angle (21°) compared to all used brines. Tweheyo et al. (Tweheyo, et al., 2006) showed that calcium ions can alter the wettability of chalk surfaces in the presence of sulfate ions at temperature of 130°C.

Figure 4 Measured contact angle of HA-MO aged calcite after treatment with various brines at atmospheric conditions.

Figure 5 Contact angle images of HA-MO droplet of aged calcite in bulk brine at room conditions. Calcite and carbonate outcrop surfaces aged in stearic acid model oil SA-MO systems Calcite and carbonate outcrop surfaces were aged in stearic acid model oil at 90°C for 5 days. The effect of salinity and ionic content of Mg2+, SO4

2- and Ca2+ ions were investigated using contact angle measurement. Figure 6 shows the measured contact angle of deionized water drop in air for aged calcite treated with DIW, SWME, SWME*, SWME*2Mg and SWME*4Mg at 90°C for 5 days before and after treatment. In all cases, calcite surface became more water-wet with SWME* being more efficient and DIW less efficient. The same contact angle measurements were repeated for similar systems but with a drop of FW in air as shown in Figure 7, calcite treated with SWME*2Mg was more effective while when treated with SWME, it was less efficient.

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Figure 6 Effect of Mg2+ ion on surface wettability alteration of SA-MO aged calcite. Contact angle is measured using drop of DIW droplet in air.

Figure 7 Effect of Mg2+ ion on surface wettability alteration of SA-MO aged calcite. Contact angle is measured using drop of FW droplet in air.

For carbonate outcrop aged surfaces, the effect of SO4

2-, Ca2+ and Mg2+ ions and salinity effect on wettability alteration was investigated. Figures 8 and 9 show contact angle measurements before surface treatment and after surface treatment with the treated brines using a drop of deionized water and a drop of formation water in air. In both scenarios, surfaces treated with SWME*0S changed surface wettability to become more water-wet. This is interesting results considering SO4

2- ions thought to be more efficient when it is added to the brine which was the case when surfaces aged with heptanoic acid model oil. Figures 10 and 11 show the measured contact angle of aged carbonate surface treated with brines that have different Ca2+ ions concentration. The results showed that the surface treated with SWME*0Ca altered the surface the most to more water-wet. In the case of aged carbonate surfaces treated with different Mg2+ ions brines, SWME*4Mg showed a significant wettability alteration to more water-wet as shown in Figures 12 and 13. Generally, all used brines caused the surface to be more water-wet but it varies without providing any particular trend. Whether a drop of deionized or formation water used to measure the contact angle, the results were similar and did not affect the final results. The effect of concentration on the aged carbonate surface did not show any preference when the surface is treated with DIW, SWME* and SWME, in all cases the surface was altered to slightly more water-wet.

Figure 8 Effect of SO42- ion on surface wettability alteration of SA-MO aged carbonate. Contact angle is measured using

drop of DIW droplet in air.

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Figure 9 Effect of SO42- ion on surface wettability alteration of SA-MO aged carbonate. Contact angle is measured using

drop of FW droplet in air.

Figure 10 Effect of Ca2+ ion on surface wettability alteration of SA-MO aged carbonate. Contact angle is measured using drop of DIW droplet in air.

Figure 11 Effect of Ca2+ ion on surface wettability alteration of SA-MO aged carbonate. Contact angle is measured using drop of FW droplet in air.

Figure 12 Effect of Mg2+ ion on surface wettability alteration of SA-MO aged carbonate. Contact angle is measured using drop of DIW droplet in air.

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10 SPE 168067

Figure 13 Effect of Mg2+ ion on surface wettability alteration of SA-MO aged carbonate. Contact angle is measured using drop of FW droplet in air.

Contact angle were also measured using a drop of model oil SA-MO in bulk brine for aged calcite and carbonate outcrop surfaces, this is to mimic reservoir condition. The contact angle measurements were performed at ambient conditions. For the salinity effect, the sample was treated with DIW, SWME* and SWME. Unlike carbonate reservoirs, the effect of low-salinity for sandstone reservoirs has been associated with wettability alteration due to the presence of clay minerals (Gupta and Mohanty, 2008; Lager, et al., 2006). Therefore, reported studies have excluded the potential of diluting seawater for carbonate reservoirs due to lack of clay minerals (Rezaei Doust, et al., 2009; Lager, et al., 2006). From Figure 14, the effect of dilution is evident. The contact angles measured for treated calcite rock with DIW, SWME* and SWME with a drop of SA-MO are 46°, 48° and 25°, respectively, while for treated carbonate outcrop surface with DIW, SWME*, and SWME, the contact angles are 35°, 37° and 21°, respectively. In short, straight dilution of Gulf sea water makes the surface less water-wet. Our results for dilution effect of the Gulf sea water on outcrop carbonate rock samples are in line with the emerged research trend stating that injecting North Sea water improve oil recovery from chalk reservoirs (Strand, et al., 2006; Zhang and Austad, 2006; Zhang, et al., 2007; Shariatpanahi, et al., 2010; Austad, et al., 2005). This effect is attributed to the reactivity of key seawater ions (SO4

2-, Ca2+ and Mg2+) that has the capability to change rock surface charges, release adsorbed carboxylic oil component from the rock surface, alter rock wettability, and eventually improve oil recovery. Fathi et al. (Fathi, et al., 2010) demonstrated through spontaneous-imbibition tests using crude oil with total acid number of 1.90, sulfate-free formation water, and chalk core samples (permeability of 1 to 3 md and porosity of 40 to 45%) that diluting seawater will decrease oil recovery. Despite the previous work focused on chalk samples and unlike our study which is being carried on calcite crystal and carbonate outcrop rock, the same trend is observed for the effect of dilution on both of the lithologies. It should also be noted that incremental oil recovery of 16-18% OIP was reported by Yousef et al, 2011 when flooding with two and ten times diluted Gulf Seawater. Their experiment were carried out using actual composite rock samples from Saudi Arabian carbonate reservoirs and live oil at a reservoir temperature of 212°F. This indicates that more investigations are needed to identify mechanism leading to this additional recovery. From Figure 14, the importance of SO4

2- ions concentration in brines on the wettability alteration of the calcite crystal and carbonate outcrop can be observed. First, the lowest contact angle for treated calcite is obtained with brine SWME*2S (contact angle of 26°) and SWME*4S brine for carbonate outcrop rock (contact angle of 21°). However, for calcite crystal, the wettability alteration does not show a reasonable trend with SO4

2- ionic concentration, in contrary to carbonate outcrop, which shows better wettability alteration (more water-wet) at higher SO4

2- concentration. For carbonate treated with SWME*0S, SWME*, SWME*2S, SWME4S, the contact angle measured were 43°, 37°, 35°, 21°, respectively. Al-Otaibi et al. (Al-Otaibi, et al., 2010) demonstrated the effect of SO4

2- ion on the wettability with three different SO42- ion concentrations

(3.56 kppm which is equivalent concentration to SWME, 1.78 kppm and 0.89 kppm) in brine/West Texas crude oil/calcite system. They observed the lowest contact angle with brine of 1.78 kppm SO4

2- ion concentration and carried out at 90°C and 2,000 psi. The effect of calcium ions in the presence of SO4

2- and Mg2+ ions on wettability of calcite crystal and carbonate rock is also shown in Figure 14. For calcite surface, it is observed that the surface treated with SWME*4Ca brine had the lowest contact angle (36°) and indicted a trend as a function of Ca2+ ionic concentration in the used brine. On the contrary, carbonate surface treated with SWEM*0Ca brine showed the most wettability alteration to more water-wet (21°) with no particular trend. The other observation in this system is the fact that calcite treated with (SWME*0Ca) showed worse wettability alteration compared to calcite treated with DIW. However, for the carbonate surface increasing calcium ion concentration turns the surface towards less water-wet.

10881 89

109123

9488

44

80

113 116

52

0

50

100

150

DIW SWME SWME* SWME*0Mg SWME*2Mg SWME*4Mg

Contact Angle 

(degrees)

Before Treatment After Treatment

SPE 168067 11

Figure 14 Measured contact angle for MO(SA) and various brines systems for calcite and carbonate In the case of Mg2+ ion in presence of Ca2+ and SO4

2-, it shows no drastic effect on surface wettability alteration. It’s worth mentioning that, when SWME0Mg brine was used, the wettability alteration was the worse for both calcite and carbonate surfaces as can be seen from Figure 14. It should also be noted that the contact angle measurements for aged calcite was repeated twice, specifically the effect of dilution in order to confirm the observed trend. The trend of wettability alteration effect on calcite showed good repeatability keeping in mind the experimental error and the homogeneity of the polished surfaces could alter slightly the exact contact angle values. Extensive work has been done on calcite by several researches (Rezaei Gomari, et al., 2006; Karoussi and Hamouda, 2004) and demonstrated the possible exchange between Mg2+ and Ca2+. Introduction of Mg2+ ions disturbs the existing equilibrium at the calcite solid surface with possible exchange/precipitation that could modify the calcite surface, hence, reducing the interaction/adsorption of stearic acid on the calcite surface. In other words, less adsorbed stearic acid remained on the calcite surface in the presence of magnesium ions compared to that for sulfate ions. In this study, the ability of Mg2+ ions to remove the adsorbed organic groups is less pronounced compared to SO4

2- ion. However, we need to keep in mind that Mg2+ ions were reported to have drastic effect when surface treatment is done above 90°C. Zhang and Hirasaki (Hirasaki and Zhang, 2004) studied the effect of divalent cations (Ca2+ and Mg2+) in the presence of SO4

2- on wettability alteration towards water-wet conditions on chalk; they concluded that SO4

2- must be present together with either Ca2+ or Mg2+ in order to improve oil recovery. Brines pH measurements Table 3 summarizes the pH measurements of calcite and carbonate systems that reflect results of Figures 4 and 14. Initial pH for all used brines was slightly alkaline and close to that of sea water (around 8), after surface treatment, brine alkalinity dropped. In the case of aged calcite in HA-MO, SWME, SWME*2Ca, SMWE*4Ca, SME*2Mg and SWME*4Mg the pH dropped by approximately one unit with a pH value close to distilled water, while SWME*0S, SWME*2S and SWME*4S the measured pH values after treatment were only slightly changed. From the wettability alteration results, SWME*0Ca showed the worst results, its initial pH value was high at 9.11 and then dropped by 1.51 to a value of 7.60. Although, SWME showed best results in terms of wettability alteration after surface treatment, its final pH value was close to the values of the other used brines. In the case of aged calcite in SA-MO, only SWME*0Ca brines dropped the most, all others dropped within half a unit except

0

10

20

30

40

50

60

70

DIW

SWME

SWME*

SWME*0S

SWME*2S

SWME*4S

SWME*0C

a

SWME*2C

a

SWME*4C

a

SWME*0M

g

SWME*2M

g

SWME*4M

g

Contact Angle (de

gree

s)

Calcite Outcrop Carbonate

12 SPE 168067

SWME*4S and SWME*0Mg which slightly changed. Although, SWME*0Ca did not alter the wettability of calcite that much, it was not the worst case scenario as compared to SWME*0Mg brine which showed minor change in pH value after treatment (8.40 to 4.34). In the final case of aged carbonate in SA-MO, only few brines changed pH (SWME, SWME*2S, SWME*0Ca and SWME*4Ca, and SWME*4Mg). The pH of all brines maintained their initial pH values of about 8. In summary, it is observed that SWME brine altered all surface to more water-wet compared to SWME* as shown by contact angle measurements and in all pH measurements, SWME pH value dropped the most. This potentially indicates that SWME brine has the capacity to remove more adsorbed spices compared to the SWME*. It is not obvious how to find a relation with the wettability alteration results in relation to pH measurements within this study and further investigation is needed to assess this issue.

Table 3 pH measurements of used brines before and after surface treatment

Conclusions The present study shows tuning or modifying the chemistry of the injected water can impact surface wettability of calcite and carbonate rocks as measured by contact angles at ambient conditions. Based on the experimental results obtained from this study, the following conclusions can be drawn:

1. Contact angle measurements have shown that oil soluble fatty acids play an important role in the wettability alteration of the calcite and carbonate surfaces. Moreover, the chain length of the fatty acids greatly influences the wettability of calcite and carbonate rock samples. Increasing the acid chain length resulted in higher contact angles (more oil-wet).

2. The procedure to measure contact angles on treated calcite crystals aged in SA-MO offers good repeatability. The crystals must appear identical to offer good repeatability and hence great care must be taken when polishing the crystals. In this study, it was shown that surfaces which were rinsed with toluene did not affect the final wettability alteration trend as compared with surfaces which were not rinsed with toluene.

3. Gulf seawater (SWME) was found to be more effective in changing the wettability of calcite and carbonate surface towards more water-wet as compared to twice diluted Gulf seawater (SWME*).

4. Sulfate ion had the largest effect on wettability alteration in the presence of magnesium and calcium ions. Sulfate is a potential determining ion towards calcite and carbonate, which has impact on the wetting state towards more water-wet. However, for calcite there exists an optimal concentration for SO4

2- (same concentration of SO4

2- in Gulf seawater) ions to give the most water-wet surface. The ratio between sulfate and calcium concentration should be as high as possible without causing precipitation of CaSO4(s).

5. The presence of Mg2+ ions has negligible effect on wettability alteration of calcite as compared to the DIW. However Mg2+ has shown a potential towards the carbonate surface and the surface is altered towards more water-wet with increasing the concentration of Mg2+ ion.

After Treatment Difference After Treatment Difference After Treatment Difference

SWME 8.20 7.13 -1.07 7.32 -0.88 7.61 -0.59SWME* 8.12 7.68 -0.44 7.50 -0.62 8.09 -0.03SWME*0S 8.13 7.94 -0.19 7.73 -0.40 8.02 -0.11SWME*2S 8.12 7.98 -0.14 7.64 -0.48 7.69 -0.43SWME*4S 8.05 7.98 -0.07 7.88 -0.17 8.16 0.11SWME*0Ca 9.11 7.60 -1.51 7.70 -1.41 8.07 -1.04SWME*2Ca 8.27 7.16 -1.11 7.75 -0.52 8.14 -0.13SWME*4Ca 8.20 7.45 -0.75 7.66 -0.54 7.86 -0.34SWME*0Mg 8.40 8.07 -0.33 8.34 -0.06 8.40 0.00SWME*2Mg 8.25 7.32 -0.93 7.68 -0.57 8.25 0.00SWME*4Mg 8.23 7.11 -1.12 7.56 -0.67 7.81 -0.42

Calcite aged in HA-MO Carbonate aged in SA-MO

pH

BrinesInitial

Calcite aged in SA-MO

SPE 168067 13

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