Investigating Enhanced Oil Recovery from Sandstone by Low

All of the cores tested were outcrop sandstone, with general data being presented in Table 2. Mineral analysis is given in Table 1. Normal-decane (n-C...
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Investigating Enhanced Oil Recovery from Sandstone by Low-Salinity Water and Fluid/Rock Interaction Aly Anis Hamouda* and Ole Martin Valderhaug University of Stavanger, 4036 Stavanger, Norway ABSTRACT: Extensive research on crude oil/brine/rock (COBR) systems has shown that the injected water composition and salinity can act as a tertiary recovery method by altering the properties of the reservoir. Because of the complexity of the COBR interactions, the mechanism(s) of low-salinity (LS) enhanced oil recovery (EOR) is still being discussed and none of the suggested mechanisms has, thus far, been accepted as the main process. In this work, the intention is to contribute to the ongoing discussions. An increase of pH associated with flooding with low-salinity water (LSW) has been observed in this work and the literature. To test the hypothesis of the effect of pH, other simpler brines than synthetic seawater (SSW) and LSW (25 times diluted SSW), such as Na2SO4 (SO42−) or MgCl2 (Mg2+) brines, were used. Those single-salt brines (LS) were selected on the basis of previous work performed in our laboratories, which showed that they increase the pH. Ion tracking of the effluent solution has clearly demonstrated mineral dissolution with pH, where ions, such as potassium (K+), were measured when LS brines (K+-free brines) were used. This was confirmed by simulation and shown to be in reasonable agreement (within 12%). A sensitivity study of the pH indicated that, at the mineral/brine interface, the pH may be higher, where a better agreement when the pH of the LS brines was increased. The pressure drop across the flooded cores showed that LSW almost doubled the pressure drop compared to that with SSW. LS expanding the electrical double layer in combination with dissolution may lead to fine detachment and mobilization that divert flooding brines and enhance the sweep efficiency. Therefore, the main factors that govern LSW performance in EOR are the degree of the mineral/brine interaction that would increase the sweep efficiency. This may explain the controversial statement in the literature on the necessity of the kaolinite content.

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INTRODUCTION

All of the cores tested were outcrop sandstone, with general data being presented in Table 2. Mineral analysis is given in Table 1. Normaldecane (n-C10) was used as a hydrocarbon phase, supplied by Chiron AS in high-performance liquid chromatography (HPLC) grade (purity >99%). N,N-Dimethyldodecylamine (NN-DMDA) were used as an oil-soluble additive to mimic amine in the oil, supplied by Fulka (purity > 99%). The structural formula is CH3(CH2)11N(CH3)2. Concentrations of 0.01 mol/L were used. Physical properties of the oil at the flooding temperature of 70 °C are as follows: viscosity, 0.48 cP; density, 0.7525 g/mL, as obtained from the simulation program PVTsim (20.1). It is assumed that the small concentration of NNDMDA does not have any significant influence on the properties of the oil; however, it adsorbs on the silicate mineral surface.15 Brines. Several different types of brine have been used in the flooding experiments. Table 3 gives the composition of the different brines. During the preparation of brines, different amounts of reagentgrade chemicals were dissolved in distilled water and then stirred by a magnetic bar for at least 3 h. When the salts were dissolved, the brine was filtered through a 0.22 μm Millipore filter to remove undissolved impurity material. The brine was, then, stored in glass bottles. Core Preparation. Cores were first dried at 100 °C for a minimum of 24 h before frequent weighing to obtain a stable weight. The cores were then saturated with synthetic seawater (SSW) under vacuum. To establish the absolute permeability, SSW at three different rates at room temperature was injected and the pressure drop was monitored. The cores were saturated with oil, and the initial water saturation was estimated. The cores were then aged at 50 °C for a minimum of 2

In recent years, controlling the salinity and composition of the injected water has become an emerging enhanced oil recovery (EOR) technique, often described as low-salinity (LS) water flooding. Modification of the water composition has shown to be an excellent way to increase recovery from both sandstone and carbonates. Many researchers have reported, from both field and laboratory tests, an increase in oil recovery by LS floodings.1−12 The understanding of the LS mechanism is however debatable, and many theories have been proposed. The complexity and number of parameters behind oil/brine/ rock interactions are the main reason. Different mechanism(s) may act together or in sequence. Various processes have been proposed for the last few years, with the most popular processes being double-layer effects,4 an increase in pH,1 migration of fines,8 multi-component ionic exchange (MIE),13 mineral dissolution,7 and microscopically diverted flow.14 Tang and Morrow8 identified these conditions for the LS flooding to be effective in Berea sandstone, a significant clay mineral fraction, in the presence of connate water exposure to crude oil to create mixed-wet conditions. However, it would seem like these conditions are not sufficient, because many outcrop sandstones fulfilling the conditions have not shown LS effects. Clay minerals have a unique property to act as a cation-exchange material, in which the capacity varies with the type of clay and quantity. Sandstone usually contains an amount of kaolinite and illite clay minerals. Polar organic material in the oil may adsorb onto clay minerals, creating a mixed-wet sandstone surface. © 2014 American Chemical Society

EXPERIMENTAL SECTION

Received: October 19, 2013 Revised: January 7, 2014 Published: January 17, 2014 898

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Table 1. Mineral Analysis of the Sandstone Used in the Experiments mineral name

chemical formula

semi-quantitive (%)

quartz kaolinite muscovite microline

SiO2 Al2Si2 O5(OH)4 (K, Na)(Al, Mg, Fe)2(Si3·Al, O10)O10(F, OH)2 KAlSi3O8

94 1 1 1

Table 2. Core Properties core number

diameter (cm)

PV (mL)

length (cm)

porosity

permeability (darcy)

Swi

flooding sequence

4 5 6 7 8 10 12

3.76 3.75 3.76 3.77 3.77 3.78 3.775

13.23 13.22 13.29 12.37 13.15 12.66 12.94

5.03 5.06 5.05 5.05 5.13 5.09 5.085

0.236 0.236 0.237 0.219 0.229 0.221 0.227

0.9 1.0 0.95 0.8 1.05 1.2 1.0

0.23 0.25 0.19 0.22 0.18 0.20 0.23

SSW LSW SSW−LSW−SSW SSW−SO4−SSW SSW−Mg−SSW Mg−LSW SO4−LSW

Table 3. Composition of Brinesa ion name HCO3− Cl− SO42− Mg2+ Ca2+ Na+ K+ TDS (g/L) ion strength (mol/L) a

SSW (mol/L)

LSW (mol/L)

0.002 0.525 0.0240 0.045 0.013 0.450 0.010 33.39 0.657

0.00008 0.021 0.00096 0.0018 0.00052 0.018 0.0004 1.3356 0.0263

Mg (mol/L)

computer to register inlet and delta pressures, a measuring buret, and a back-pressure valve. A confining pressure of 20 bar was maintained throughout the tests, to simulate reservoir conditions and give a good seal between the shrinkable sleeve and core. A back pressure of 10 bar was used. The inlet pressure and pressure difference across the core were recorded using a Labview 2012. Produced fluids, both effluent water and produced oil, were sampled and recorded. The pH was measured and logged throughout the test. A sketch of the flooding setup is shown in Figure 1. For all floodings, either brine or oil injection, the core was weighed before and after to check for any discrepancy between the measured volumes and calculated saturations. Assuming a 100% fluid-saturated core, the volumes of different fluids can be checked by simple calculations based on the density of the fluids. As the core was mounted in the core holder, it was first wrapped with a double layer of Teflon tape. The heat-shrinkable sleeve was then fitted by heating. The inlet and outlet of the core holder were blocked to prevent any fluid loss from the heating. A Dionex ICS-3000 ion chromatograph was used to measure the anion and cation contents of the produced water for selected samples. The samples were first diluted, 1−200 times for high-salinity produced water and 1−50 times for LS produced water. In total, seven core

SO4 (mol/L)

0.09 0.0240 0.045 0.048 4.2844 0.135

3.414 0.072

All concentrations values are in mol/L.

weeks before flooding at 70 °C with the selected brine, and effluent fluids were collected. The core flooding setup consisted of an oven to adjust the flooding temperature, a Gilson 305 pump, a piston cell, a core holder, a

Figure 1. Sketch of the experimental flooding setup. 899

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Figure 2. Oil recovery and pH for primary core flooding with SSW and LSW with different rates (linear scale) as a function of the injected pore volume: (left axis) recovery and (right axis) pH.

Figure 3. Pressure drop across the cores for primary flooding with SSW and LSW at different rates.

Figure 4. Oil recovery and pH as a function of injected PV for primary flooding with SO42− and Mg2+ at 4 PV, followed by LSW at flooding rates of 4 and 16 PV/day. floodings were conducted. The flooding temperature was 70 °C. The flooding sequence is given in order in Table 2.

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Primary Oil Recovery. Figure 2 compares oil recovery and the measured pH for primary injection of SSW and LSW. All of the cores were first flooded at a rate of 4 pore volumes (PV)/ day (0.035 mL/min) until the oil production stopped (approximately at 4 PV), and then the flooding rate was increased to 16 PV/day (0.14 mL/min). This was performed to check for possible capillary end effects. A sharp increase of oil production was observed until breakthrough, after which almost no oil was produced. The ultimate recovery was about 31% for SSW and 22% for LSW. No incremental oil recovery was obtained by increasing the

RESULTS AND DISCUSSION

This work may be divided into two parts. The first part is a comparison between SSW and LS [LS water (LSW) or singleion brines SO42− or Mg2+] as primary oil recovery injection fluids. In the second part, SSW is the primary oil recovery fluid and other brines, LS (LSW and single-ion brines SO42− and Mg2+), are used for the secondary recovery. 900

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Figure 5. Comparison between the pressure drop across the core during primary flooding with Mg2+ and LSW.

Figure 6. Comparison between the pressure drop across the core during primary flooding with SO42− and LSW.

Figure 7. Oil recovery from secondary flooding with LS (Na2SO4 and MgCl2) and LSW, following SSW. At the end of the flooding, the cores were reflooded with SSW for any additional oil recovery.

flooding rate to 16 PV/day, which may be due to the fact that the increase of the injection rate was small relative to the core permeability; hence, no fluid diversion toward the unswept zones of the core occurred. The pH of the injected SSW was about 7.9 and 7.75 units for the influent and effluent, respectively. The slightly decrease in pH during injection of SSW is consistent with the observations by other researchers.16,17 The pH values of the injected and effluent liquid were within 8 units. The decrease in the pH was between 0.15 and 0.3 units. Although the decrease in the pH was relatively small, it was reported by different researchers. The pH reduction may be due to hydration of magnesium ions. Figure 3 shows an average pressure drop of about 19 mbar in the case of primary LSW flooding compared to that for SSW, which was about 10 mbar for the first 2 PV, and then the pressure fluctuated between 5 and 2 mbar. Lager et al.13 stated in their model that clays are sites where oil acidic/basic components could be adsorbed, and this makes the rock oil-

wet. Oleic components are desorbed from clay surfaces during flooding with LS that makes the rock more water-wet. The pressure drop increased from 8 to 10 mbar when the injection rate increased to 16 PV. In the case of LSW, it is interesting to see that the pressure drop remained almost constant at 20 mbar for both injection rates. Comparison between oil recoveries by single-ion brines (Na2SO4 and MgCl2) are shown in Figure 4. Oil recovery is about 23% from both SO42− and Mg2+, which is almost the same as that for the primary flooding with LSW (Figure 2). No additional recovery was obtained when switched to LSW at both flooding rates. The pH reached about 9.3 and 8.1 in the case of SO42− and Mg2+, respectively, at about 3 PV injection and rate of 4 PV/day. When the flooding rate with LSW increased, the pH decreased to about 7.54 and 7.24 in the cores having initial SO42− and Mg2+ brine flooding, respectively. The pressure drop (dP) increased from 3.8 to 8 mbar after 2.5 and 3.5 PV injection of Mg2+ (Figure 5). When the brine was 901

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Figure 8. pH as a function of PV during flooding with different brines. SSW is the primary flooding solution, followed by LS (LSW, Na2SO4, and MgCl2).

Figure 9. Ion tracking, with cation concentrations (mol/L) of different ions in the effluent as a function of the flooded PV with different brines.

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Figure 10. Ion tracking, with anion concentrations (mol/L) in the effluent as a function of the flooded PV with different brines as indicated.

Figure 11. Normalized dimensionless anion concentrations, [Cl−]nd, [SO42−]nd, and [HCO3−]nd, and pH (secondary axis) as a function of injected PV of LSW.

switched to LSW, dP fluctuated around 8.2 and then increased to about 13 mbar, which is about 7 mbar less than in the case with primary flooding with LSW (Figure 2). This may be due to the fact that brine/mineral interaction has reached equilibrium, leading to less interaction. This is addressed later in the section of the proposed mechanism. In the case of SO42− flooding, it was interesting to see that the dP has a wavy shape that fluctuates between about 5 and 8 mbar (Figure 6). The pressure drop had almost a linear dP increase with PV injected after about 0.3 PV from switching to LSW. The pressure drop than reached a maximum of 13 mbar. Secondary Oil Recovery by LS. The next set of cores were flooded with SSW as primary injection fluid and then flooded with different brines for secondary recovery with low

and high flooding rates. In general, almost no increase of oil recovery was observed for any of the flooding brines. Figure 7 shows the secondary recovery from LS (SO42− or Mg2+ or LSW) after primary flooding with SSW as a function of normalized PV; i.e., PV = 1 of LSW is equivalent to 4 PV from the start of the primary flooding with SSW. The 3% difference in the recovery for SSW is not exactly known. Despite the fact that the cores are similar in the general properties, their pore size distribution may not be similar. This is indicated by the low Swi and high permeability for core 8 compared to cores 6 and 7. The pH of the injected LSW was about 7.4 and increased to about 8.25 at the effluent after about 4 PV injected LSW at 4 PV/day (Figure 8). A further increase of the injection rate, 16 PV/day, showed an increase to about 8.5. In the case of Mg2+ 903

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Figure 12. Dilution factor of the dimensionless cation concentration as a result of switching from SSW to LSW.

Figure 13. Normalized dimensionless concentrations of [HCO3−]nd, [SO42−]nd, [Ca2+]nd, and [Mg2+]nd as a function of the injected PV of Na2SO4 as a secondary fluid after SSW.

flooding, the pH of the effluent increased from 7.7 to about 8 after flooding with 4 PV at a rate of 4 PV/day. When the flooding rate was increased to 16 PV/day, the pH started to decline after about 9 PV and reached about 7.8 after flooding for 12 PV. In the case of secondary flooding with SO42−, the pH increased, from about 7.7 to 9.1 after flooding with about 4 PV at a rate of 4 PV/day. A further increase of the pH to about 9.7 was observed with an increase of the flooding rate to 16 PV/ day. Ion Tracking/Fluid Interaction and Possible Oil Recovery Mechanisms by LSW. Figures 9 and 10 give an overview of the concentration of the tracked cations and anions in the effluent during flooding with various brines as a function of PV, respectively. This section is divided into two parts. The first part is dimensionless analysis to understand and compare the interaction between the flooding fluids and the minerals. In the second part, ion interactions with reservoir minerals and a proposed mechanism for EOR by LSW is discussed. From the previous sections, the pH was shown to increase in the flooding cases with Na2SO4, LSW, and to lesser extent in

the case of MgCl2. The observation of the pH increase was consistent in the case of primary and secondary flooding by LS fluids at the rate of 4 PV/day. However, by increasing the flooding rate to 16 PV/day, the pH declined in the case of primary flooding and increased in the case of secondary flooding. In the case of secondary Na2SO4 flooding, it was shown that the increase of the pH was associated with the HCO3− decline (Figure 11). Figure 11 shows normalized dimensionless anion concentration decline curves, when switched from SSW to SO42−, for [Cl−]nd, [SO42−‑]nd, and [HCO3−]nd and pH values as a function of the injected PV. The dimensionless concentration is estimated as the ratio between the measured ion concentrations at different PVs to the corresponding measured ion concentration in SSW at the time of switching to flooding with LSW. It is interesting to see the corresponding change of [HCO3−]nd with pH. [HCO3−]nd was constant until about 2 PV flooding with LSW; then it declined; and pH increased. Theoretically, ion concentrations in LSW should correspond to 25 times the diluted ions in SSW, i.e., reach 0.04 of the SSW ion concentration, assuming no interaction with the minerals. In practice, this would take a large number of flooding PVs to 904

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flooding with SSW and sulfate brines, respectively. The dotted vertical lines indicate the switching of the flooding fluids, while the solid vertical line indicates the increase of the flooding rate from 4 to 16 PV/day. There was an increase of about 13% of [K+], from 0.016 to 0.018 mol/L, after about 0.3 PV of switching from SSW to SO42−, and then [K+] declined to reach an average concentration of about 0.0027 mol/L (after about 2.5 PV injection of SO42−). The declining trend of [Na+] was almost the same as for potassium. [Na + ] reached a concentration of about 0.049 mol/L after injection of about 2.5 PV of Na2SO4, which is almost the same concentration in Na2SO4. K+ reached a minimum (of about 0.0002 mol/L) and then increased almost linearly to 0.0027 mol/L after about 5 PV with a increasing flooding rate to 16 PV/day and before switching back to SSW, where [K+] reached about 0.011 mol/L (almost as in the SSW), after about 1.5 PV. The increase of the potassium ion concentration with the flooding rate may be explained by an increase of fresh fluid in contact with the mineral surface, which increases the ion exchange between Na+ and K+ ions. The ion exchange may be presented by the following reaction for the potassium-containing minerals (such as in the core material) represented by K-feldspar (orthoclase).

reach the theoretical value. The main dilution process, when switching to LS fluids, is mainly by dispersion (diffusion and convection). The estimated dilution factor of the cations when switching to LSW is shown in Figure 12 as the concentration ratio expressed as dimensionless [Mn+]d (ratio between the measured cation concentration at the time of switching to LSW to that measured during the flooding with LSW), as a function of the injected PV of injected LSW. The largest ion dilution appears to happen for sodium [Na+]d, where it reached about 17 times the dilution factor, while in the case of K+ ions, it was about 16 times the dilution factor. Both Mg+ and Ca+ ion dilution factors were about 10 and 8 times, respectively. Figure 13 shows the normalized dimensionless measured concentrations for [HCO3−]nd, [SO42−]nd, [Cl−]nd, and [Ca2+]nd during the flooding with SO42− solution. At first glance, the trend of [SO42−]nd with the injected SO42− solution appeared incorrect, where the concentration exceeded the injected concentration; however, this may indicate an additional source of SO42− ions, such as dissolution of the precipitated CaSO4 during the SSW flooding. It is expected that [Ca2+]nd would reach almost zero as a result of the dilution. However, [Ca2+]nd has reached a constant concentration of about 0.058 after about 2.5 PV of injected SO42−. The [Ca2+]nd of 0.058 is equivalent to about 6% of the calcium ion concentration in SSW. [Cl−]nd reached 0.0072, which is equivalent to about 0.5% of the concentration in SSW. Therefore, if we assume that the minimum concentration of [Cl−]nd is the equivalent to what is caused by the dilution, within the injected PV, and then apply this to the Ca2+ ion, the calcium ion concentration as a result of dilution would then be equivalent to about 5.5% that in SSW (≈0.0015 mol/L of Ca2+). This may mean that there are other sources of calcium ions that contribute to the increase of the calcium ion concentration. The mineral content does not indicate the presence of mineral-bearing calcium. Another possible source of calcium is from the dissolution of precipitated sulfate salts during SSW flooding or from carbonate-cementing materials that reacted with SO4 2−. Figure 13 also shows that [HCO3−]nd is almost constant at about 0.3 after the initial drop in the concentration. The source of HCO3− may suggest the presence of carbonate cement. As shown in Figure 13, the initial concentration of Ca2+ was slightly higher (about 7%) than that in SSW, which is within the measurement uncertainty. Figure 14 shows the change of [Na+] and [K+], in mol/L, as a function of injected PV during the primary and secondary

KAlSi3O8(s) (orthoclase) + Na + = K+ + NaAlSi3O8(s) (albite)

(1)

Figure 5 shows that the pH reached 9.1 after about 4 PV of primary Na2SO4 flooding for the injection rate of 4 PV/day. When the injection rate was increased to 16 PV/day, the pH increased to about 9.7 and also [K+] increased from a minimum of about 0.0002 to 0.0027 mol/L. An increase of pH may be explained by mineral dissolution, which increases [K+]. The reaction may be presented as follow: 4KAlSi3O8(s) (orthoclase) + 22H 2O = Al4Si4O10 (OH)8 (s) (kaolinite) + 8H4SiO4 (aq) + 4K+(aq) + 4OH−(aq) +

(2)

−

Produced H4SiO4, K , and OH increase the alkalinity of the effluent solution. This may explain the increase of the pH and K+ concentration. Equations 1 and 2 demonstrate the possible sources of K+ as a result of Na+ ion exchange with K+ in the potassiumcontaining clay minerals and also mineral dissolution. Equation 2 demonstrates that, as the dissolution takes place, the alkalinity as a result of H4SiO4, K+, and OH− increases. Therefore, pH increases as a result of ion exchange and dissolution. Figure 8 demonstrates the increase of pH when the flooding fluid was switched from SSW to Na2SO4. The pH increased initially to 7.8 after 5.4 PV and then to about 8.1 after 7.4 PV, and then at 8.2 PV, the pH reached about 9.3. This exponential increase may demonstrate two processes. The first is the increase of the pH as a result of flooding with Na2SO4 solution.18 The second is that the increase of the pH triggered the dissolution of kaolinite, which then contributed to the further increase of the pH to about 9.3 at a flooding rate of 4 PV/day. Both LSW and MgCl2 showed an increase of pH to approximately 8 after about 8 PV with an injection rate of 4 PV/day. With a further increase of the flooding rate to 16 PV/day, pH of the effluent of LSW flooding increased to about 8.5 after about 3 PV at a flooding rate of 16 PV/day, while in the case of MgCl2 flooding, the pH declined to about 7.8 for the same PV as that for LSW. In the

Figure 14. Sodium and potassium ion concentrations (mol/L) during SSW and Na2SO4 flooding at an injection rate of 4 and 16 PV/day, as indicated by the vertical solid line. 905

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Figure 15. Comparison between [K+] in mol/kg of water obtained from the simulation and experiments. Simulation of K-feldspar dissolution by LSW and LS (MgCl2 and Na2SO4) brines.

Figure 16. Simulated and experimental [K+], mol/kg of water, as a result of K-fledspar/MgCl2 as a flooding brine at various temperatures and pH values.

explained by the fact that bound Mg2+ to HCO3− and CO32− in SSW20 hydrolyzes as it flows through cores as a result of the interaction with minerals, forming MgOH+ and releasing H+. Huertas et al.21 studied the kinetics of the dissolution of kaolinite by following the evolution of dissolved Si and Al concentrations at various pH and reported that the dissolution rate of kaolinite displays strong pH dependence and Al sites form negative surface complexes above pH 9. The above section concentrated on the interaction between the fluid and the minerals to explain the different observations. An increase of the pH is not directly related to an increase of the oil recovery. Recalling oil recovery, the results show higher oil recovery from SSW (the average pH was about 7.8) compared to other flooding with LS fluids. However, in the secondary flooding, LS fluid shows a slight increase in the recovery from SO4 and LSW.

case of LSW, [K+] increased similarly to that in the case of flooding with Na2SO4, indicating possible dissolution, as explained above. However, in the case of MgCl2, the reduced pH with the increase of the flooding rate, may be due to the possible formation of Mg(OH) 2 (s) (brucite) or Mg4(CO3)3(OH)2·3H2O(s) (hydromagnesite). Stumm and Morgan19 stated that hydromagnesite could be formed at room temperature as metastable with respect to magnesite (MgCO3). However, the stability diagram for brucite requires pH > 10.7 to be stable. This may suggest the possible formation of hydromagnesite,20 which may explain the observed reduction of the pH, as the bulk [OH−] becomes associated with the formed complex. In the case of SSW, pH was reduced between 0.15 and 0.3 from the injected pH of about 7.8. This was also observed by other researchers, as indicated earlier. The reduced pH may be 906

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Figure 17. Simulated and experimental [K+], mol/kg of water, as a result of K-fledspar/Na2SO4 as a flooding brine at various temperatures and pH values.

Mg2+ flooding, which has a pH close to LSW, the recovery was slightly lower. LS expands the double layer, and the dissolution disturbs the mineral integrity, leading to fine detachment and mobilization. This has been shown in earlier sections of this paper. This may then enhance the sweep efficiency. In other words, a high content of clay minerals could have a reverse effect that leads to formation damage and oil trapping. To create liquid diversion by increasing the flooding rate showed no additional recovery. This may be explained in two ways: the rate is not high enough to divert the flooding liquid as a result of the relatively high permeability, and another alternative explanation is that the trapped oil could not be reached by LSW, hence, no effect from the increased velocity.

Simulation. The simulations are performed using Phreeqci (geochemical program). The simulation was based on solid/ solution equilibrium. The solid in this case was orthoclase based on eq 2. The solutions were the different examined brines. Figure 15 compares simulated [K+] from the interaction between K-feldspar with LS brines and LSW as a function of the temperature. Experimental results (simulated, at 68 °C) shows [K+] of 6.4 × 10−4 (8.1 × 10−4), 1.9 × 10−4 (1.52 × 10−4), and 1.8 × 10−4 (1.64 × 10−4) for LSW, SO42−, and Mg2+, respectively, expressed in mol/kg of water. For comparison, the lowest [K+] was taken rather than the initial concentration in the brine, because the dilution processes will not be 100%. In the case of LS brines, the simulation underestimated [K+], while in the case of LSW, it was overestimated. This may be due to the difference in the pH at the mineral surface and that measured in the bulk solution. Sensitivity was run on the effect of pH for the used brines, as shown in Figures 16 and 17, for brine flooding with MgCl2 and Na2SO4, respectively. It is interesting to see that the experimental and simulation data, in the case of Mg2+ and SO42− flooding, fit well when the simulations were performed at higher pH, i.e., 10 and 10.5, respectively. Results obtained by Blum and Lasaga22 and Huertas et al.21 indicate that deprotonation of the aluminum sites is the rate-limiting step and Al sites form negative surface complexes above pH 9, contributing to the dissolution. Flooding with LSW and LS brines showed an increase of the pressure drop across the core. The pressure drop reached ≈20, 8, and 6 for primary flooding with LSW, SO4, and Mg, respectively. In the case of SSW, the maximum pressure drop was ≈10 mbar. The pressure drop fluctuation in the case of SO4 (wavy shape averaged between 8 and 4 mbar) and the two-step increase (4 and then 6 mbar) in the case of Mg2+ may suggest mobilization of the detached particles. Huertas et al.21 demonstrated that the rate constant has inflections at about pH 4 and 10, where above and below these values, the dissolution rate displayed strong pH dependence. In this work, it was demonstrated that, as the dissolution and/or ion exchange (eqs 1 and 2) take place, the pH increases. Both LS (SO42−) and LSW show similar oil recovery, while with

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SUMMARY AND CONCLUSION This work may be divided into two main parts. The first part is to understand the fluid/mineral interaction, and the second part is to identify the link between the fluid/mineral interaction and possible LS EOR mechanism(s). The first part of this work was divided into primary and secondary flooding to compare the liquid/mineral interaction by tracking the changes in the ion concentrations. The potassium ion was selected, because it is present in the mineral and absent in the LS liquids. Experimental results were compared to the simulated cases for LS and LSW, using Phreeqc geochemical software. The simulation overestimated [K+] compared to the measured [K+]. A sensitivity study was carried out for the effect of the pH on K-feldspar dissolution. The results were almost identical at pH values of 10.5 and 10, for SO42− and Mg2+, respectively. These interesting results may indicate a higher pH at the interphase between the liquid and minerals, hence, increased mineral dissolution. However, for the LSW/K-feldspar interaction, the simulation results showed underestimation of [K+] compared to that obtained by the experiments. A sensitivity study for the pH showed that, when the pH was increased to >9.0, the runs became unstable. Therefore, a relatively low [K+] was obtained compared to the experimental results, which could not be explained on the basis of the pH at the interface as performed 907

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on LS cases. This may suggest that the buffer capacity of LSW is higher than that in the case of LS. The experimental analytical results showed constant HCO3−, indicating the possible presence of CaCO3 as cementing material, which may also emphasize the fact that not only could dissolution be the main cause of wettability alteration but also the reduced double-layer effect combined with dissolution could enhance particle detachment, divert the flooding fluid, and enhance sweep efficiency. However, a high rate of detachment may cause formation damage. This may explain the controversial finding in the literature of, in some cases of low kaolinite, a better EOR performance by LSW than higher kaolinite, which was stated to be a perquisite. In other words, the presence of minerals that interact with the flooding brine that could enhance fine migration and, thus, the sweep efficiency.

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AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The authors acknowledge the support from the technical staff at the Department of Petroleum and Engineering, University of Stavanger.

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REFERENCES

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dx.doi.org/10.1021/ef4020857 | Energy Fuels 2014, 28, 898−908