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Feb 23, 2017 - ESal, 1938 Harney Street, Laramie, Wyoming 82070, United States ... The additional oil recovery from fractured and oil-wet carbonates b...
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Effect of the Temperature on Wettability and Optimum Wetting Conditions for Maximum Oil Recovery in a Carbonate Reservoir System M. Adeel Sohal,*,† Geoffrey Thyne,†,‡ and Erik G. Søgaard† †

Department of Chemistry and Bio-science, Aalborg University, 6700 Esbjerg, Denmark ESal, 1938 Harney Street, Laramie, Wyoming 82070, United States

‡

ABSTRACT: The additional oil recovery from fractured and oil-wet carbonates by ionically modified water is principally based on changing wettability and often attributed to an improvement in water-wetness. The influence of different parameters, such as dilution of salinity, potential anions, temperature, pressure, lithology, pH, and oil acid and base numbers, to improve waterwetting has been tested in recovery experiments. In those studies, the temperature is mainly investigated to observe the reactivity of potential anions (sulfate and borate) at different concentrations. However, the influence of systematically increasing the temperature on wetting conditions has not been thoroughly investigated. In this experimental study, the effect of different temperatures on wettability for brines of different ionic strength and composition has been investigated in depth. A series of flotation experiments was conducted at 23, 50, and 100 °C using Dan outcrop chalk. The effect of each individual variable on the wetting condition was tested independently. The brines included seawater, seawater without sulfate, seawater (augmented with 2−4 times sulfate), and seawater containing borate instead of sulfate. All brines were diluted 2, 4, 10, 20, and 100 times. It was observed that, as the temperature increased, the water-wetness decreased for seawater and seawater dilutions; however, the presence of elevated sulfate can somewhat counter this trend because sulfate increased oil-wetting.

1. INTRODUCTION The additional oil recovery from fractured and oil-wet carbonates is principally based on wettability alteration. Several methods, such as chemical flooding, caustic flooding, alkaline flooding, injection of nanoparticles and ionically modified water, etc., have been implemented to improve water-wetness. Ionically modified water that is also known as advanced water, smart water, LoSal, etc. is the most economical enhanced oil recovery (EOR) method1 because of low capital investment and operating cost. It is also one of the most environmentally friendly methods and most appropriate alternatives of lean gas injection in the regions where the source of such resources is not available. It is the most feasible method for lowpermeability oil-wet reservoirs, where the other chemical EOR methods have injectivity and mobility issues. However, it is still a lab-scale process and demands a thorough understanding of the mechanisms to become popular at the field scale. One of the factors that hinder field-scale implementation is the lack of mature mathematical models that are needed to simulate the results before field application. The other aspect is related to its field or reservoir specificity, unlike low-tension and thermal methods. However, despite these facts, a number of experimental studies have been performed at diverse operating conditions. In these studies, different rock−crude oil systems were used to gather valuable insights of the mechanisms. The first common outcome of the studies was increased recovery related to improvement in water-wetness.2,3 Therefore, the first effort that was made to acquire this milestone was tuning of injected water chemistry. The injected water chemistry approach was tested in both ionic composition and ionic strength, but the underlying mechanisms were different.4 © XXXX American Chemical Society

Therefore, coreflood and imbibition experiments were performed using brines of different ionic compositions and strength at different operating conditions. In imbibition experiments, commonly outcrop chalk and synthetic brines of different ionic compositions were investigated.5−15 This work found that SO42− together with Ca2+ and Mg2+ is reactive and has the potential to change the oil-wet conditions. Romanuka et al.16 gathered the same results in chalk imbibition experiments. Gupta et al.17 also used the same approach and found phosphate and borate more reactive than sulfate during coreflooding. Most of the low-salinity waterflood has been conducted in limestone cores by Yousef et al.2,18−20 The brines of low ionic strength have modified carbonate rock oil-wetting nature in coreflooding experiments. The recovered additional oil as a result of low salinity has been attributed to the expansion and stabilization of the thin water film between the oil and rock surface.21 In addition to brine chemistry, the influence of pH, temperature, and oil acid number (AN) and base number (BN) on oil-wet conditions has been investigated. Legens et al.22 found that the carboxylic acids of crude oil adsorb on the calcite surface and render it oil-wet. Fathi et al.13 observed that crude oil containing a higher concentration of naphthenic acids showed more oil-wetting characteristics. Mwangi et al.23 discovered that longer chained naphthenic acids made the chalk grains more oil-wet compared to short-chained acetic acid. Mahani et al.24 performed surface complexation modeling and showed that, at low pH conditions in low-salinity water, H+ Received: October 9, 2016 Revised: February 16, 2017 Published: February 23, 2017 A

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Energy & Fuels ions turn the rock surface positive, while it becomes negative at high pH conditions as a result of OH− ions in solution. Therefore, a positively charged calcite surface promotes oilwetness, and a negative surface improves water-wetness. Puntervold et al.25 demonstrated in spontaneous imbibition experiments that 90 °C is the lowest temperature range for the SO42− ion to react with the chalk surface for wettability alteration. 1.1. Temperature Effects. It was observed by Strand et al.8 in the chromatographic separation test that the adsorption of the sulfate ion on Stevns Klint outcrop chalk increased as the temperature increased from 23 to 130 °C in spontaneous imbibition experiments. Zhang and Austad26 tested the temperature and AN effect on wettability. They aged the cores at 40, 80, and 100 °C for 30 days and measured wettability. They concluded that the temperature had little effect between 40 and 80 °C and saw a slight decline in oilwetness between 80 and 120 °C. Contact angle studies show an increase in water-wetting at higher temperatures. Hamouda and Gomari27 measured the contact angle of the n-decane droplet on the calcite surface treated with 0.01 M stearic acid in ndecane at elevated temperatures. The advancing contact angles for these systems were 160°, 131°, and 90° ± 3° for the pretreated surface at 25, 50, and 80 °C, respectively. However, they did not observe any significant change in the receding contact angles for the same system. A decrease in oil contact angles at higher temperatures has also been observed by Thomas et al.28 and Hjelmeland and Larrondo.29 However, contact angle measurements can be challenging with variation as a result of the surface condition, drop size, salinity, and AN being important factors.30,31 If water-wetness increases with the temperature, we would expect recovery to improve as well; however, recovery does not increase with the temperature in some cases. Hamouda and Karoussi32 observed a decline in the recovery from 48 to 26%, corresponding to relative permeability data at the temperatures of 80 and 130 °C, respectively. On the basis of these studies, the effect of the temperature on wetting is not clear. The differences could be due to different rock−crude oil−brine systems used in the experiments. In this experimental study, we thoroughly investigated the temperature effect on chalk-wetting conditions at 23, 50, and 100 °C for the same rock−crude oil system. Moreover, the effect of brines of different ionic strength and composition were investigated for the three temperatures. It was observed that, as the temperature increased from 23 to 100 °C, the water-wetness decreased. This declining trend of the water-wet fraction with the temperature was found in all of the tested brines.

Table 1. XRF Analysis of Outcrop Dan Chalk species

%

CaCO3 SiO2 Al2O3 MgCO3 total CO3

96.2 1.25 0.17 0.54 96.74

2.2. Brines. All of the synthetic brines that were used in this study were prepared by mixing reagent-grade salts in deionized water (DIW). The brines consisted of synthetic seawater, low-salinity brine (seawater without sulfate), borate brines (seawater containing borate anion instead of sulfate), and seawater with 2−4 times more sulfate than the normal concentration. The compositions of these brines were taken from the published literature,34 and dilutions were performed by adding DIW. The compositions, ionic strengths, total dissolved solids (TDS), and densities of all of the different brines are listed in Table 2. The densities of all brines were determined by a DMA 35 Anton Paar density meter at 23 °C. The molar concentration of the borate anion is a bit less than that of sulfate (SO42− in normal seawater (SW). The lower concentration of borate was used to avoid the precipitation problems at room temperature observed for higher concentrations. The symbol D represents the dilution and precursor numeric value fold of dilutions. 2.3. Crude Oil. In this experimental study, the same crude oil was used as described by Sohal el al.33 The oil was centrifuged at 3800 rpm for 1 h to remove the solid particles and water. The AN and BN of crude oil characterize the polar components that develop adhesion to the rock surface. These components are neutralized by a strong base or acid and then calculated by the consumed quantity. In this study, a potentiometric titration method is used to determine these numbers with TitroLab 90 from Radiometer Analytical that consists of a control unit TIM 90 (pH meter), buret station ABU 900, and sample still SAM 7. The titration method was initially developed by Dubey and Doe35 and then revisited by Fan and Buckley.36 In this study, the potentiometric titration method from Metrohm was used (given in OILPAC collection analysis). The density of crude oil was measured by a DMA 35 Anton Paar density meter, and the viscosity at 25 and 90 °C was measured by a PVS rheometer from Brookfield. The crude oil properties are listed in Table 3. The oil BN was also verified by Eurofins Lab, Norway. 2.4. Initial and Final Brine pH. Initial and final pH of brines were measured by PHM-210 from Radiometer Analytical. The borate brines showed higher pH values compared to seawater and low-salinity brines. The initial and final pH of all of the brines were measured at room temperature (23 °C), but the final pH was measured after treating the brines at respective temperatures. The collected samples clearly showed the effect of the temperature on pH, as depicted in Table 4. The variation in the pH value is an indication of precipitation or dissolution of CaCO3 that leads to estimation of the possible type of surface charge between the interfaces. The type of charge between the interfaces increases or decreases the oil adhesion onto the rock surface. The opposite charges between oil−brine and rock−brine interfaces create attraction, while similar charges produced repulsion. Therefore, attraction leads to oil-wet surfaces, while repulsion produces water-wet surfaces. 2.5. Flotation versus Contact Angle. In this study, the flotation technique was used to determine wettability. Details of the methodology are described by Sohal et al.33 The method is very simple and fast and produced highly repeatable results in days instead of months. It captures the wettability changes at the grain-scale level and quantitatively measures the oil-wet and water-wet fractions of the reservoir rock. Moreover, it can be used to test the effect of different temperatures, brines, crude oils, and reservoir rocks on wettability, as investigated in this study. The flotation method of the wettability measurement has already been compared to the published imbibition experiments.33 Although the crude, brine, and rock systems were

2. MATERIALS AND METHODS 2.1. Rock Material. In this study, the same outcrop Dan chalk material was used that has been described by Sohal et al.33 The elemental composition of the chalk material was measured by an X-ray fluorescence (XRF) technique using Lab-X 3000 XRF equipment from Oxford Instruments. The elemental composition of Dan chalk was converted into oxides and given in Table 1. Total CO3 refers to the total carbonates in the above-described analysis; in this case, it comprised Ca and Mg carbonates. The chalk samples were dried at 100 °C for 2 weeks, ground with a ball mill, sieved to a mesh size between 50 and 100 μm, and preserved in a glass jar. A minor amount of smaller grain size may be found in the sieved material. A sample of chalk powder was dried at 100 °C for 2 weeks to verify the moisture content, which was almost zero. Therefore, the mass of 1.0 g of sample represents the given species. B

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Energy & Fuels Table 2. Ionic Composition (mmol/L), TDS, Ionic Strength, and Density of All Used Brines brine

Ca

Mg

SO4

Na

CI

HCO3

K

[B4O5(OH)4]

ionic strength (mol/L)

TDS (g/L)

density (g/cm3)

SW × B × OS 2D × SW × B × 0S 10D × SW × B × 0S 20D × SW × B × OS 100D × SW × B × OS SW 2D × SW 10D × SW 20D × SW 100D × SW SW × OS 2D × SW × OS 10D × SW × OS 20D × SW × OS 100D × SW × OS SW × 2S 2D × SW × 2S 10D × SW × 2S SW × 4S 2D × SW × 4S 10D × SW × 4S VB

12.992 6.496 1.299 0.650 0.130 12.992 6.496 1.299 0.650 0.130 12.992 6.496 1.299 0.650 0.130 12.992 6.496 1.299 12.992 6.496 1.299 29.249

44.515 22.257 4.451 2.226 0.445 44.515 22.257 4.451 2.226 0.445 44.515 22.257 4.451 2.226 0.445 44.515 22.257 4.451 44.515 22.257 4.451 7.870

0.000 0.000 0.000 0.000 0.000 24.007 12.004 2.401 1.200 0.240 0.000 0.000 0.000 0.000 0.000 48.015 24.007 4.801 96.029 48.015 9.603 0.704

420.446 210.223 42.045 21.022 4.204 450.107 225.053 45.011 22.505 4.501 460.443 230.221 46.044 23.022 4.604 498.121 249.061 49.812 594.151 297.075 59.415 995.962

525.142 262.571 52.514 26.257 5.251 525.142 262.571 52.514 26.257 5.251 583.493 291.746 58.349 29.175 5.835 525.142 262.571 52.514 525.142 262.571 52.514 1064.559

2.024 1.012 0.202 0.101 0.020 2.024 1.012 0.202 0.101 0.020 2.024 1.012 0.202 0.101 0.020 2.024 1.012 0.202 2.024 1.012 0.202 8.928

10.060 5.030 1.006 0.503 0.101 10.060 5.030 1.006 0.503 0.101 10.060 5.030 1.006 0.503 0.101 10.060 5.030 1.006 10.060 5.030 1.006 4.695

9.177 4.589 0.918 0.459 0.092 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

0.612 0.306 0.061 0.031 0.006 0.657 0.328 0.066 0.033 0.007 0.643 0.322 0.064 0.032 0.006 0.729 0.364 0.073 0.873 0.436 0.087 1.113

32.158 16.079 3.216 1.608 0.322 33.392 16.696 3.339 1.670 0.334 33.391 16.696 3.339 1.670 0.334 36.802 18.401 3.680 43.622 21.811 4.362 62.798

1.021 1.009 1.000 1.000 0.998 1.022 1.010 1.000 0.999 0.997 1.022 1.010 1.000 0.999 0.998 1.025 1.011 1.000 1.030 1.014 1.001 1.041

are different but there is still a good match of the wettability trends. The water-wet fraction increases (from 39 to 49%) as the contact angle decreases (from 90° to 62°) with dilution of seawater, as shown in Figure 1.

Table 3. Crude Oil Properties AN (mg of KOH/g)

BN (mg of KOH/g)

viscosity at 25 °C (mPa s)

density at 25 °C (g/cm3)

0.52

1.60

11.94

0.862

3. RESULTS 3.1. Effect of the Dilution and Temperature on Wettability: Seawater without Sulfate. These results are most applicable to experimental systems that use NaCl solutions for measurements because formation water has a content of sulfate. In general, dilution caused a modest increase in water-wetting up to 10-fold dilution, but further dilution has little effect at a constant temperature. The largest overall shift in wettability with dilution was observed at 100 °C, as shown in Figure 2. The shift toward water-wetting was much less for the same degree of dilution at 23 and 50 °C. Overall, a higher temperature made the grains more oil-wet. Wettability shifted as much as 30% from 23 to 100 °C for the full-strength solution. The more dilute solutions have less shift in wettability from the temperature with no significant shift from 23 to 50 °C for the 2-, 10-, and 20-fold dilutions. However, a systematic shift with the temperature was seen for the most dilute solution (100D). We see that the crude oil−brine−rock system is shifted toward oil-wetting as the temperature increases; therefore, reservoir carbonate is more oil-wet compared to samples measured at surface conditions. The relationship between the temperature and wettability for the more saline solutions is not linear but becomes more linear as the salinity decreases. Most important from the practical aspect, dilution can significantly shift the system back toward water-wetness, releasing oil from the rock at higher temperatures. Lower temperature systems will be more water-wet initially and have less wettability shift with dilution. 3.1.1. Effect of the Dilution and Temperature on Wettability: Seawater. The synthetic seawater has chemistry closer to field conditions. The solution contains sulfate; therefore, the experiments are measuring change in wettability

Table 4. Initial and Final pH of Brines at 23 °Ca

a

brine

23 °C brine pH

100 °C final pH

50 °C final pH

23 °C final pH

SW × B × OS 2D × SW × B × 0S 10D × SW × B × 0S 20D × SW × B × 0S 100D × SW × B × 0S SW 2D × SW 10D × SW 20D × SW 100D × SW SW × OS 2D × SW × 0S 10D × SW × OS 20D × SW × OS 100D × SW × OS SW × 2S 2D × SW × 2S 10D × SW × 2S SW × 4S 2D × SW × 4S 10D × SW × 4S

8.74 8.86 8.97 8.85 8.64 7.93 8.05 7.61 7.35 7.15 7.90 7.16 7.34 7.12 6.06 8.00 7.96 6.52 7.94 8.01 6.60

8.30 7.63 8.17 8.11 8.22 7.43 7.66 7.83 7.99 8.08 7.76 7.40 7.81 7.99 8.12 7.18 7.40 7.65 6.83 7.53 7.82

8.65 8.47 8.16 8.41 8.52 7.44 7.74 7.79 8.42 8.62 7.19 7.53 7.97 7.92 7.99 7.34 7.48 7.80 7.49 7.77 8.23

8.74 8.61 8.17 8.24 8.60 7.56 7.80 8.06 7.92 8.24 7.47 7.53 7.97 7.95 8.03 7.54 7.75 7.89 7.56 7.70 7.91

Final pH was measured after treating brines at given temperatures.

different in both techniques, there was a good match of the produced results. In this study, the flotation results of change in wettability using diluted seawater are compared to the change in contact angle at 100 °C from Yousef et al.2 In both methods, the crude and rock systems C

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Figure 1. Comparison of the change in contact angle2 with the water-wet fraction and wetting index by increasing the dilution of seawater at 100 °C.

Figure 2. Comparison of the effect of different temperatures and low-salinity brines on wettability. Error bars represent ±5%, the experimental uncertainty associated with the flotation technique.

by both sulfate and dilution effects. In some studies, the influence of the temperature on the reactivity of potential anions toward carbonate surfaces has been tested by spontaneous imbibition. However, these tests were limited to the sulfate reaction.8,14 Shehata et al.37 recovered additional oil by injecting DIW in tertiary and secondary recovery modes in reservoir limestone cores, suggesting that dilution can improve wettability without the presence of sulfate. In this study, the effect of the temperature on wettability was observed by experiments at 23, 50, and 100 °C in the same crude oil−rock system. Moreover, we observed the impact of different dilutions of brines on wettability for the three temperatures. Dilution of synthetic seawater slightly increased water-wetness up to 10fold dilution, and then water-wetness was not significantly improved for the same temperature, as shown in Figure 3. The magnitude of shift in wettability with dilution was small at 23 and 50 °C but much more pronounced at 100 °C. Again, the largest shift in wettability with dilution was observed at 100 °C.

The total change in wettability from dilution never exceeded 16% and was smaller at lower temperatures. Sayyouh et al.38 found that a higher temperature increased oil-wetting for Saudi sandstones, and Zhang and Austad26 found that oil-wetness increased with an increasing temperature for chalk. The seawater experiments also show more oil-wet conditions at higher temperatures. The largest shift in wettability with the temperature was observed for the full-strength solution. This effect is decreased as the solutions are more diluted with no significant shift in wettability with the temperature for most dilute solutions. This is different from the 20D and 100D solutions without sulfate (see Figure 2). The data show experiments Ca+) and turns the positive surface charge to negative (>CaSO4−), as found in surface complexation modeling.24,39 A postive carbonate surface charge can produce adhesion with carboxylic acid groups through polar attraction, turning the surface more oil-wet. This agrees with our data and again suggests that dilution will be much more effective at shifting wettability at common reservoir conditions (higher temperature and brines with sulfate). This finding is different from the case for surfactants where the extent of wettability alteration decreases at higher salinity.17 3.2. Effect of the Sulfate Concentration on Wettability. The potential of synthetic seawater containing 2 and 4 times more sulfate than seawater at given temperatures is depicted in Figure 4. The impact of 4 times (0.096 mol/L) and

2 times (0.048 mol/L) sulfate in seawater on wettability at 23 and 50 °C is minimal, as also observed at 40 and 80 °C by Zhang and Austad.11 However, the most important finding is that increasing the amount of sulfate in brine did not significantly improve water-wetness, except at low concentrations (∼0.002 mol/L = 10D × SW) in this crude oil−brine− rock (CBR) system at 23 and 50 °C. Exactly the same effect was observed by Shariatpanahi et al.40 in chalk imbibition experiments at room temperature and 50 °C. They found that oil recovery and water-wetness did not improve when the concentration of sulfate increased to more than 2 mmol/L, the same effect that was observed in current flotation experiments. However, when they increased the temperature to 100 and 130 °C, the water-wetness and oil recovery decreased for the same concentration of sulfate in brine. The flotation results given in Figure 4 show the same effect. At 100 °C, the water-wetness decreased and continued to decrease as the amount of sulfate E

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Figure 5. Effect of the increasing temperature and concentration of borate in SW on wettability and final pH of brines.

Figure 6. Comparison of chalk wettability alteration by SW, SW × 0S, and SW × B × 0S brines at room temperature.

effect of the temperature on wettability was observed from 23 to 50 and 100 °C in the same crude oil−rock system. Additionally, we observed the impact of different dilutions of brines on wettability for the three temperatures. Overall, the borate brine increased oil-wetting on chalk at 23 °C compared to seawater. Dilution of borate brine at 23 °C increased waterwetting up to 20-fold dilution (0.5 mmol/L), but further dilution did not further increase water-wetting. At 50 °C, the same pattern was observed but dilution did not improve waterwetting after 20-fold dilution. At 100 °C, the water-wetness decreased up to 10% compared to 23 °C but the overall pattern of increasing water-wetness with dilution is the same, because no more improvement could be seen after 20D. The 100 °C experiments were complicated by observations of precipitate formation, as detected in aqueous stability testing. This is assumed to be a borate salt that is relatively insoluble at higher temperatures. The precipitation was observed up to 4-fold dilutions and, thus, may have lowered effective borate concentrations in the brine. Therefore, borate improves oil-

increased in the system. Therefore, the increased temperature (⩾90 °C) and sulfate concentration (>0.002 mol/L) decreased the oil recovery and rendered the chalk more oil-wet in imbibition experiments.40 The same effect on wettability is observed in the flotation experiments. Therefore, the improved water-wetness in flotation experiments could imply some degree of enhanced oil recovery, but that correlation remains to be determined. 3.3. Effect of the Dilution and Temperature on Wettability: Borate Brine. The synthetic borate brine experiments are measuring change in wettability by both borate and dilution effects. The potential of the borate anion toward the carbonate surface has been tested in limestone coreflood experiments at 250 °F by Gupta et al.17 In these experiments, the concentration of the borate anion was not given and additional recovery was considered to be due to wettability change. However, there were no direct measurements of wettability, such as contact angle measurements, to determine the degree of wettability change. In our study, the F

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Figure 7. Plotting of data based on WI calculated by flotation results at 100 °C.

thick water film at pore walls, which bridges the pore throats (snap-off), as described by Muggeridge et al.47 Therefore, shifting the wettability of such systems toward oil-wet conditions decreases the thickness of the water film at pore walls and allowed for the oil droplets to reconnect for a continuous oil film, which is relatively easy to displace. Salathiel45 stated that, if oil paths are continuous in a mixedwet system, water could displace oil from larger pores and little or no oil would be held by capillary forces in small pores. Jadhunandan and Morrow41 stated that the maximum oil recovery near neutral wettability is more appealing because it can be argued that the capillary forces are minimized. Therefore, it is imperative to know the initial wetting conditions of the reservoir rock before starting a wettability alteration EOR process. It will help to decide which way wettability has to be shifted for optimum oil recovery. 4.2. Flotation Wettability Index (FWI). In flotation experiments as described above, the potential of each injected fluid to alter the wettability in either direction can be easily determined. The maximum potential of ionically modified water to shift the wettability depends upon the available degree of alteration that has been explained in a previous work.33 The optimum wetting conditions can be easily determined with the help of newly defined FWI, which is based on flotation results. The FWI works in the same fashion as the Amott−Harvey WI and can be easily calculated with the help of eq 1.

wetting as did sulfate with an increasing temperature, as shown in Figure 5, but is prone to precipitation at higher temperatures, which may limit the effect in field applications. The comparison of all three brines at tested temperatures revealed that dilution of SW shifted the wettability more than SW × 0S and SW × B × 0S, as seen in Figure 6. However, it is clear from this figure that there is a sharp change in wettability alteration (30%) with dilution in the case of borate, whereas it is only 3−6% in the case of SW × 0S and SW at 23 °C, respectively. However, our data show that borate brines have less potential to improve water-wetness at 23 and 50 °C compared to SW and SW × 0S. The fact behind this difference is that the active anionic form of borate brine that attaches to carbonate metal ion sites (>Ca + ) is only 5−10% at experimental pH values, while sulfate is more than 50% reactive, as described by Sohal el al.33 ,

4. DISCUSSION 4.1. Optimum Wettability. Most proposed mechanisms regarding injection of ionically modified water in carbonates attribute the improved oil recovery to wettability alteration, by either potential determining ions (PDIs) or decreasing the total salinity of injected water. In these studies, incremental production has been ascribed to improved water-wetness.2,3,9,11−13 However, a number of studies linked the additional oil production to the mixed-wet or neutral-wet state.20,41−43 Dandekar44 plotted the residual oil saturation (Sor) and oil recovery curves against the wettability index (WI) that were based on the coreflood results.41,45,46 According to these curves, the maximum reduction in Sor and improvement in oil recovery is achieved at a WI of 0−0.25 (from neutral-wet to weakly water-wet). A further increase in water-wet conditions neither improves the oil recovery nor decreases the residual oil saturation. The explanation of this effect is the trapping of oil as individual droplets at higher water-wet conditions following snap-off. Therefore, it is almost impossible to recover that oil, even by increasing the injection pressure. Therefore, in extreme water-wet conditions, oil is trapped as isolated droplets in the center of the pores as a result of the

FWI = (mass of water‐wet fraction) − (mass of oil‐wet fraction) total mass (1)

The FWI value varies between −1 and +1 that represents completely oil-wet to completely water-wet conditions, respectively, and 0 indicates the mixed-wet or neutral-wet conditions. The WI based on flotation results is plotted in Figure 7 for different brines. It can be clearly seen that the Dan chalk becomes oil-wet (FWI = from −0.85 to −0.35) in VB, SW × 2S, SW × 4S, and SW × B × 0S brines, whereas in SW and 20D × SW, the chalk wettability is close to neutral-wet G

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Figure 8. Increasing trend of chalk oil-wetness with an increasing temperature.

conditions (FWI = from −0.25 to +0.25) in this rock−crude oil system. It is found that the sulfate concentrations greater than 2 mmol/L increase the oil-wetness of Dan chalk. Dan chalk also becomes oil-wet in Valhall brine (VB), and we speculate that the shrinkage of the electrical double layer as a result of high ionic strength of VB may favor oil-wetting. Finally, it is concluded that, in this rock−crude oil system, 20D × SW is providing the optimum results compared to all of the other brines at 100 °C. For example, if VB is the formation water, then by injecting 20D × SW this CBR system would shift wettability up to 30% toward water-wet conditions to reach the optimum wetting conditions where the Sor is at minimum level according to the plotted curve. Jadhunandan and Morrow41 calculated the WIs as a function of the temperature for North Sea and West Texas crude oils. The core samples were taken from Berea sandstone and aged in respective crude oils at temperatures of 20−80 °C. They plotted WIs against aging temperature and observed a decreasing trend of water-wetness with an increasing temperature. Our flotation results show the same trend of decreasing water-wetness with increasing temperature for chalk in all of the tested brines. The data for seawater are shown in Figure 8 as an example. Shariatpanahi et al.40 found in chalk imbibition experiments at 100−130 °C that increasing sulfate more than 2 mmol/L promoted oil-wet conditions and oil recovery decreased. In flotation experiments, the increased concentration of sulfate in seawater rendered the system more oil-wet, as seen in Figure 4. The same trend was observed for borate, with its effect even more severe than that of sulfate, as depicted in Figure 5. The effect of both ions to change the wettability toward oil-wet conditions is more prominent at 100 °C compared to 23 and 50 °C. The sulfate property to turn the reservoir system more oil-wet could be useful for initially strongly water-wet reservoirs by shifting the wettability closer to the neutral-wet state. However, elevated sulfate could create scale problems, limiting applicable amounts. The sodium tetraborate salt produced precipitates at 100 °C in aqueous stability testing. Moreover, borate salt dissociation in DIW produced only 5−10% anionic species to react with the carbonate surface for wettability

alteration compared to sulfate, as described by Sohal et al.33 Therefore, borate field-scale application does not seem very plausible. In a majority of the coreflood experiments, additional oil recovery as a result of advanced water injection has been attributed to improved water-wetness without measuring the initial and final wetting conditions of the used core samples. Therefore, using additional oil recovery as a metric to judge the wettability alteration is not practical. As described above, the optimum oil recovery and Sor are attained close to neutral-wet conditions. However, injected water compositions may turn the reservoir system from water-wet to oil-wet or vice versa without achieving optimum conditions. Hazim et al.20 carbonate coreflood experiments illustrated this fact. They recovered up to 62% of original oil in place (OOIP) by injecting UmEradhuma (UER) brine in reservoir core plugs at 25 °C. This amount of oil recovery with formation water (FW) indicates that the cores were initially water-wet. Therefore, when they systematically increased sulfate (11.7, 23.7, 47, and 69.7 ppm) in 5000 ppm of UER brine, recovery gradually increased from 83 to 87.2% at 4 times the sulfate (47 ppm) concentration and then decreased to 61.5% when diluted UER brine containing 6 times sulfate (69.7 ppm) was injected. If this coreflood recovery pattern is fitted on the oil recovery curve, as shown in Figure 7, it seems that increasing the sulfate concentration shifted the wettability of the reservoir system from right to left (water-wet to past neutral-wet conditions) because sulfate shifts wettability to more oil-wet.

5. CONCLUSION In flotation experiments, it was observed that all of the treated brines showed higher water-wet fractions at a low temperature. The degree of the chalk oil-wet fraction increased at a higher temperature. Dilution of all brines improved the water-wetness compared to original concentrations, and the wettability shift reached a maximum at 10D in most of the cases. However, at lower temperatures, the difference in wettability change was not that significant. The data show there are two separate effects that shift wettability, changing salinity and changing PDI concentrations. Dilution increases water-wetness, while increasing sulfate promotes oil-wetting of chalk. A higher temperature H

DOI: 10.1021/acs.energyfuels.6b02612 Energy Fuels XXXX, XXX, XXX−XXX

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is required for sulfate to work. The increasing concentration of sulfate and borate turned the chalk more oil-wet, and the effect was significant at 100 °C. The overall potential of borate brine to change the wettability was less than SW and SW0S at 23 and 50 °C, but within its own dilution, the effect was very sharp from 0D to 10D. Knowledge of initial wetting conditions aids in the design of the appropriate water composition to shift the wettability in the right direction (oil-wet to water-wet or vice versa) for optimum results. These wetting conditions can be more easily determined by flotation experiments with the help of newly defined FWI.

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AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. ORCID

M. Adeel Sohal: 0000-0002-0584-7273 Notes

The authors declare no competing financial interest.

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REFERENCES

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DOI: 10.1021/acs.energyfuels.6b02612 Energy Fuels XXXX, XXX, XXX−XXX