In this section, the effects of the initial wettability of the calcite samples on the performance of four different brines, three of them are smart considering the effects of salinity and the Mg
2+ and SO
42− ions are discussed. The mechanism of the wettability alteration process was investigated using measurements of brine properties before and after CA measurement and energy-dispersive X-ray spectroscopy (EDX) analysis. The technique used to measure CA was utilized to determine the wettability of calcite surfaces in presence of Hsal and three different smart brines, listed previously in
Table 1 as Lsal, SW1, and SW2. The average initial CA of the calcite samples was 45°, indicating a strong water-wet state.
The differences in the CA for the Hsal and Lsal brines can be explained by the mechanism of calcite dissolution illustrated in
Figure 4. During the aging process in Hsal and Lsal brines, calcite (CaCO
3) dissolution takes place. Consequently, Ca
2+ ions are present as free ions in the solution, leaving CO
32− as binding sites on the surface. For the Hsal case in
Figure 4a, Na
+ and Cl
− ions are present in high concentrations, giving Na
+ ions a chance to accumulate on the surface since they are attracted to CO
3−. This process can also be considered to involve a strong cation exchange between Ca
2+ at the surface and Na
+ within the brine. This mechanism changes the surface charge to slightly positive, which increases the attraction of negative carboxylic groups. Since there is no difference in CA between the clean samples and the Hsal pre-aged samples, it can be speculated that aging in Hsal resembles the initial condition of the sample.
As the aging period in oil elapsed, the CA increased toward an oil-wetting condition. This behavior may be related to the strong adsorption of polar organic components of the crude oil on the calcite surfaces [
17]. After 40 min of aging in oil, the CAs for the two groups became similar, showing a similar adsorption process of polar molecules. The wettability alteration in this case was relatively fast, due to the presence of long acidic chains of molecules in the oil sample. Jabbar et al. [
25] emphasized the role of polar compounds in oil and acidity in the wettability alteration of carbonate rocks and found that more oil-wet conditions are achieved as the length of acid chain increases.
3.2. Effect of NaCl Aqueous Solutions (Hsal and Lsal) on the Wettability Alteration Process
Based on the results, the brine with high-salinity NaCl aqueous solution could only weakly alter the wettability of the sample, whereas the low-salinity NaCl brine had the ability to alter the wettability rather than a neutral wetting state or an oil-wet state to more water-wet state. Lashkarbolooki et al. [
19] reported similar results, noticing that the CA decreased as the salinity of NaCl solutions decreased. They found that a brine of 45,000 ppm NaCl could change the CA from 138.8° to 98.1°, and a brine of 5000 ppm NaCl changed the CA from 148.4° to 35.6° after 10 days of aging.
Three mechanisms are proposed here for the wettability alteration process: the salting-out effect, double layer expansion, and microscopic dissolution of carbonate rock:
During the salting-out mechanism, the solubility of a nonelectrolyte substance in water decreases with increases in salt concentration in brine. Firstly, the non-electrolyte carboxylate molecule has lower solubility in brine with higher salt concentrations. As the salinity of the brine increases, the salting-out effect leads to a decrease in the solubility of carboxylic compounds, resulting in the deposition of more organic materials as the thin oil phase near the rock surface increases the chance of bonding between the positively charged carbonate surface and negatively charged carboxylic components. Conversely, a lower salt concentration increases the solubility of carboxylic groups. Active ions with negative charges tend to be attracted to the positive calcite surface and substitute for the calcium ion, which is bonded to the negative molecules of carboxylates; hence, the wettability of the surface becomes less oil-wet.
Secondly, the term “double layer” refers to the bulk of the ions that are close to the surface, which form due to the interaction between the charged rock surface and the brine. The distribution of charges at the surface is composed of opposite charges (counter-ions) attracted to the surface and other equal charges (co-ions) repulsed from the surface in an aqueous medium. Because of this charge accumulation, an electrical layer is formed. During LSW in carbonate rocks, the surface tends to be less positive, due to the ionic exchange between cations in the aqueous brine and calcium ion. The substitution of calcium ions with the aid of a solvation process results in the detachment of adsorbed oil. This leads to double layer expansion, and ultimately results in the wettability alteration (i.e., more water wet) of the rock surface, as illustrated in
Figure 14.
The final step is the dissolution of calcite (CaCO3), which takes place as the low-salinity brine invades the carbonate surface. For the Hsal and Lsal samples, the lack of calcium ions promotes the dissolution of calcite, and thus oil is expelled from the surface.
For Cases 4 (oil wet) and 5 (strongly oil wet), the values of the WAI for Lsal ranged from 0.58 to 0.77 after both two days and two weeks. This indicates that the process of wettability alteration is completed within about two days. It also shows that there is a limit for wettability alteration by Lsal brine, since this did not exceed a value of about 0.8. For Hsal brine, the WAI was approximately the same for Cases 3 (neutral wet) and 4 (oil wet), showing that the adsorption of carboxylic compounds did not reach wettability equilibrium although the initial wettability was different. It therefore appears that the initial wettability does not affect the wettability reversal by Hsal brine. All binding sites on the surface of calcite are fully filled after one month of aging in crude oil, even if the CA does not increase further after two days of aging in crude oil.
3.3. Effect of Smart Waters (SW1 and SW2) on the Wettability Alteration Process
The aqueous solution SW1 contains only Mg
2+ as an active ion for wettability alteration, while SW2 contains both Mg
2+ and SO
42− as potential ions. As the CA was altered from 90.8° to 25.3° in Case 3 (neutral wet) and from 130° to 27.6° in Case 4 (oil wet) by SW1, this reveals that the magnesium ion can alter the wettability of the calcite surface in the absence of the sulfate ion. This result agrees with the work of Rashid et al. [
15], who observed a reduction in CA from 148° to 13°. These authors concluded that the presence of the sulfate ion is not important for wettability alteration by Mg
2+, although the presence of the SO
42− ion increases the concentration of Mg
2+ near the carbonate surface via a reduction in the electrostatic repulsive force. The pre-adsorbed carboxylate molecules decrease the electrostatic repulsive force, allowing Mg
2+ to be sited near the surface. In the initial stages, the solubility equilibrium between solid calcite and its component ions, Ca
2+ and CO
32−, is established as expressed by the chemical equation:
Then, the magnesium ion starts to disturb this equilibrium through its reaction with some of the CO
32− ions to form MgCO
3 precipitate. Consequently, the chemical reaction is shifted to the right. As a result, calcite dissolution is promoted, which generates an excess of calcium ions over the calcite surface. These calcium ions can react with adsorbed carboxylic groups and remove them from the surface [
26]. Finally, the dissolution of calcite and desorption of organometallic complexes out of the calcite surface lead to a wettability alteration for the rock to a more water-wet state. Carbon dioxide gas may be produced in negligible amounts, causing only a slight reduction in pH.
The chemical reaction for this mechanism is suggested to be as follows:
It is generally believed that magnesium ions can change the wettability of an oil-wet calcite surface. However, the correct mechanism(s) of wettability change is not completely understood. Petrovich and Hamouda [
27] observed an increase in calcium ions and a decrease in magnesium ions in the produced water and linked this to the substitution of Ca
2+ ions on the calcite surface by Mg
2+ ions in the injected water. This observation can be accompanied with the chemical reaction in Equation (3), as Mg
2+ ions react with CaCO
3 and result in MgCO
3 precipitate. Hence, calcium ions are detached by the reaction and remove carboxylic compounds from the surface, and the wettability is changed from oil-wet to water-wet.
SW2 has a significant effect on wettability alteration for all wettability ranges. As depicted in
Figure 15, the electrostatic repulsive force is reduced by the adsorption of sulfate ions onto the positively charged sites of the calcite surface. This phenomenon leads to a higher magnesium ion concentration close to the surface. The adsorbed sulfate ions reduce the density of the positive charge on the surface, resulting in desorption of loosely adsorbed carboxylates. This mechanism means that the wettability alteration by magnesium and sulfate ions is faster than that of magnesium ions alone, and SW2 therefore shows better results in terms of wettability alteration than SW1.
It is clear that the WAI is approximately the same for SW2 after both two days and two weeks. This indicates that the wettability alteration process by SW2 is complete within two days. SW1 has a lower WAI after two days than after two weeks; this can be associated with an incomplete process of wettability reversal due to a lack of the sulfate ion, which has a catalytic role during the alteration of surface wettability by the magnesium ion. SW1 has a similar ability to alter the wettability to that of SW2, but it is slower, reaching a similar value to that of SW2 after two weeks.
In terms of the WAI for Case 3 (neutral wet) calcite samples, SW1 and SW2 had approximately similar values, which were higher than those for Cases 4 and 5 after aging for two days. This shows the effect of initial wettability on the success of smart brines. The oil aging period for Case 3 (neutral wet) is shorter than that for Cases 4 (oil wet) and 5 (strongly oil wet), and the adsorption of polar compounds is therefore lower, as reflected by the lower CA for Case 3 (neutral wet). This indicates that the wettability alteration process is faster when the initial wetting condition is intermediate or neutral.
pH measurements were conducted before and after the treatment of the calcite surfaces in different brine aqueous solutions. The initial and final pH values of the brines were recorded for all cases. pH values before and after aging in brine for one day at the start of the main test range from 5.55 to 9.13 and from 5.71 to 9.52 for Hsal and Lsal brines, respectively. There is a significant increase in the pH values, from a slightly acidic condition to a basic condition for both brines (Hsal and Lsal). The change in pH value was higher in the case of the Lsal brine. This increase can be related to the dissolution of calcite (CaCO
3). Because of this mechanism, a large amount of hydroxide ions (OH
−) may be released based on the chemical equations below, thus increasing the pH values. As the salinity of the solution decreases, the invasion of the calcite surface increases and the dissolution becomes larger.
At low pH values, the calcite surface tends to be positively charged, due to the presence of calcium ions. In contrast, at a higher pH, the concentration of carbonate ions (CO
32−) is high, which makes the charge of the surface become negative [
28]. Hence, more repulsions occur between the surface and carboxylic groups as the pH increases. The same trend of an increase in pH was observed when calcite samples with different initial wettability were aged in the Hsal and the Lsal brines, as shown in
Table 8.
The decrease in the pH values of SW1 and SW2 is due to the reaction expressed in Equations (3) and (6).
The production of carbon dioxide results in reduction of pH values, even if this reduction is small. This can be justified by the small amount of CO
2 produced by the equilibrium reaction. The precipitation of magnesium carbonate was recognized as white powder at the top of the calcite surface in the form of dendritic magnesite; the MgCO
3 mineral (
Figure 16).
Our main objective here was to correlate the oil recovery under various synthetic brines with the initial wettability of the formation. As mentioned earlier,
Figure 1 shows the relationship between the initial wettability effect and oil recovery during water flooding for the Berea sandstone. It is clear that the Recovery Factor (RF) increases as the initial wetting state changes from water-wet to neutral wet and decreases as the initial wettability changes from a neutral-wet to an oil-wet condition. This behavior can be associated with the results of the CA for the Case 1 samples (strongly water wet). It can be concluded that, it is not beneficial to use Lsal or other smart brines for wettability alteration process when the initial wetting state is water-wet as no change was observed in wettability during the experiments. In contrast, Hsal brine can alter the wettability back to a more neutral-wet state, which can be a good choice in water flooding experiments due to its higher recovery rate. For Case 2 (preferentially water wet), Hsal is better than Lsal and the smart brines (SW1 and SW2) as it can keep the samples at the same CA values. Therefore, for these two cases (Case 1 and Case 2 or strongly and preferentially water wet), the most favorable wettability alteration can be achieved by the injection of Hsal brine.
For Case 3 (Neutral wet) samples with intermediate or neutral wetting state, Hsal brine would be the best option from an economical point of view to keep the CA within a range similar to the initial wettability. Other brines tend to decrease the CA significantly, which can decrease the water permeability and cause water blockage leading to lower oil recovery. For the samples with initially oil-wet states in Cases 4 and 5, Lsal and the smart brines (SW1 and SW2) are the best options for incremental oil recovery. These brines tend to decrease the wettability of the reservoir from oil-wet to more neutral and water-wet conditions. In Case 5, Hsal brine is not a good choice for the water flooding of a strongly oil-wet reservoir. LSW is effective in oil-wet carbonate reservoirs, as wettability changes from an oil-wet state to a water-wet state. Ultimately, this reaches an unfavorable water-wet condition that decreases the recovery. Hence, it would be more beneficial to switch to high-salinity water flooding to move back to a natural state after the injection of LSW. In practice, based on the results obtained from this research work, some scenarios can be developed incorporating different smart brines to manage the reservoir rock wettability to facilitate the flow conditions for oil and maximize the oil recovery through smart water flooding in carbonate oil reservoirs.