Low Salinity EOR Effects in Limestone Reservoir Cores Containing

Sep 23, 2015 - Mechanistical study of effect of ions in smart water injection into carbonate oil reservoir. Mostafa Lashkarbolooki , Shahab Ayatollahi...
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Low Salinity EOR Effects in Limestone Reservoir Cores Containing Anhydrite: A Discussion of the Chemical Mechanism T. Austad, S. F. Shariatpanahi, S. Strand, H. Aksulu, and T. Puntervold* University of Stavanger, 4036 Stavanger, Norway ABSTRACT: It is well accepted that seawater injection is able to improve the water wetness of carbonate reservoirs at high temperatures, and in that way, it can act as an enhanced oil recovery (EOR) fluid. A recent laboratory investigation showed that increased oil recovery also was obtained from carbonate reservoir cores by successively flooding composite limestone cores by 2, 10, and 20 times diluted seawater. The study confirmed that it is possible to obtain low salinity EOR effects also in carbonates, and not only in sandstones. In the present study, preserved reservoir core material from a similar limestone formation was used with the objective to obtain a chemical understanding of the mechanism for the improved oil recovery. It was verified, that the core material contained significant amounts of anhydrite (CaSO4), which appeared to be the key factor for observing the low salinity EOR effect. The concentration of sulfate in the injection brine increased due to increased dissolution of anhydrite as the salinity and concentration of inactive salt, NaCl, decreased. Both an increase in the sulfate concentration and a decrease in NaCl content in the injected brine will have a positive effect on the wettability alteration process. An oil displacement test was conducted on a restored reservoir core at 100 °C using 100 times diluted formation water in a tertiary flooding process, after first injecting formation water. This showed a low salinity EOR effect of 22% of original oil in place (OOIP), corresponding to an 88% increase in oil recovery. Also 30 times diluted seawater increased the oil recovery by 18% of OOIP in a tertiary flood after first flooding the core with formation water. After flooding a core successively at 100 °C with formation water, seawater, and 10 times diluted seawater, the oil recovery increased gradually by 25, 30, and 33% of OOIP. The chemical low salinity EOR mechanism was discussed in terms of dissolution of anhydrite and a decrease in the NaCl concentration. This wettability alteration mechanism is, in principle, the same as that reported previously for injection of seawater and modified seawater into chalk cores, involving a symbiotic interaction between Ca2+, Mg2+, and SO42− at the rock surface. In this case, supply of extra Ca2+ and SO42− was obtained by dissolution of anhydrite. The low salinity EOR technique can have a great economic potential regarding oil recovery from high temperature carbonate reservoirs containing significant amounts of dissolvable anhydrite distributed in the pore space.

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INTRODUCTION Enhanced oil recovery (EOR) by injecting low salinity water into sandstone reservoirs containing clay minerals has been observed in the laboratory and also documented in field tests.1−3 The mechanism for the increased oil recovery has been debated during the last 10−15 years, and it appears to be generally accepted that a wettability alteration linked to clay minerals takes place. A new chemical understanding of the process has recently been published, which involves desorption of active cations from the clay surface promoting an increase in pH at the clay−water interface.4,5 A local increase in pH desorbs basic and/or acidic polar organic crude oil components from the clay surface by an ordinary acid−base reaction. Seawater is regarded as a “smart” EOR fluid in carbonates at high temperature. By a symbiotic interaction between polar acidic carboxylic material, that dictates the oil wetness of calcite surface, and the active cations Ca2+, Mg2+, and SO42−, seawater has the ability to increase the water wetness of the rock surface and improve the oil recovery.6 Therefore, the chemical mechanism for wettability modification is completely different for sandstone and carbonate. The efficiency of seawater as a wettability modifier in carbonates could be improved by removing NaCl from seawater and by spiking the NaCl depleted seawater with sulfate.7−9 Compared to spontaneous imbibition of ordinary seawater, an increase in oil recovery from chalk cores at 90 °C © XXXX American Chemical Society

was observed, corresponding to an extra 9 and 24% of OOIP (original oil in place), using NaCl depleted seawater and NaCl depleted seawater spiked with sulfate, respectively.8 It is important to note that by just diluting seawater to 1600 ppm, the oil recovery decreased drastically compared to seawater, from 61 to 17% of OOIP.7 Thus, the extra oil recovery from pure carbonates by modifying the seawater cannot be linked to the traditional low salinity EOR effect observed in sandstones, where diluted high salinity brines promoted extra oils in secondary or tertiary water floods. Recently, Yousef et al.10 showed that improved oil recovery was achieved when successively flooding composite reservoir carbonate cores with 2, 10, and 20 times diluted seawater. The oil recovery in each step increased by an additional 7, 9, and 1.5% of OOIP, respectively, after first flooding the core with ordinary seawater. The authors pointed out that the mechanism for the improved oil recovery was probably different from previous published work on carbonate and sandstone. Pu et al.11 have reported tertiary low salinity EOR effects ranging from 3 to 9.5% of OOIP in sandstone cores with very Received: May 18, 2015 Revised: September 23, 2015

A

DOI: 10.1021/acs.energyfuels.5b01099 Energy Fuels XXXX, XXX, XXX−XXX

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Energy & Fuels

kerosene was displaced by n-heptane, and at the end, ∼3 PV (pore volume) of DI water was injected to remove brine and easily dissolvable salts. The injection rate was 0.1 mL/min. Finally, the core was dried at 90 °C to constant weight. Core Restoration. Initial water saturation (Swi) of 10% was established by using the desiccator technique.16 The cores were equilibrated for 3 days in a sealed container to establish uniform water distribution. The core with initial water saturation was mounted in a core holder, evacuated for air for a short time, saturated and flooded with crude oil, 2 PVs in each direction. Chemical equilibrium between the phases was supposed to be achieved by aging the core for 2 weeks in a pressurized cell (10 bar) at reservoir temperature, 100 °C. Core Flooding Experiments. Oil Recovery Test. The restored core was mounted in a Hassler core holder with a confining pressure of 20 bar and back-pressure of 10 bar. The core was equilibrated at reservoir temperature for 12 h prior to the test. The displacement test was performed by successively flooding the core with the different injection brines at constant rate. The amount of produced oil and water was monitored, and produced water samples were collected for chemical analyses. Oil recovery as percent of OOIP was plotted against the PV of the brine injected. Dissolution of Anhydrite, CaSO4. The effects of salinity, temperature, and injection flow rate on the dissolution of anhydrite were studied. A mildly cleaned and 100% water saturated core was mounted in a Hassler core holder with a confining pressure of 20 bar and backpressure of 10 bar. The core was equilibrated/aged at the actual temperature prior to the test and then flooded at different rates with the specific brines. The brines used were DI water, FW0S, d100FW0S, GSW, and d10GSW. Effluent samples were collected in sealed vials and analyzed for Ca2+, Mg2+, and SO42−. The concentrations were plotted against the PV injected. Analyses. SEM and EDS Microanalysis. A Zeiss Supra 35VP field emission microscope (SEM), equipped with an energy dispersive spectrometer (EDS) using accelerating voltages down to 0.2 kV for optimum surface detail, was applied. Small limestone rock samples were placed on a carbon adhesive disc mounted on an aluminum stub. A thin platinum layer was applied to avoid charging of the samples. Chemical Analysis. The chemical analyses of the water samples were performed on a ICS-3000 reagent-free ion chromatograph produced by Dionex Corp., Sunnyvale, CA, USA. Effluent samples were diluted 10−1000 times before analyses, and the ionic concentrations of Ca2+, Mg2+, and SO42− were calculated based on external standards. Brine Modeling. The brine modeling was performed with OLI Systems stream analyzer 3.2 software. This chemical model is based on thermodynamic equilibrium conditions using a database based on published experimental data. The dissolution of anhydrite in different brines at various temperatures was calculated.

low clay content, but containing significant amounts of dolomite and anhydrite. In a recent work, tertiary low salinity EOR effects were observed in limestone reservoir core material containing small amounts of anhydrite, CaSO4(s), but no LS EOR effect was observed when using core material free from dissolvable anhydrite.12 Thus, the condition for observing low saline EOR effects in limestone is that dissolvable anhydrite must be present in the rock. The objective of this work is to discuss/confirm a chemical mechanism for low salinity EOR effects in carbonates, by using preserved core material containing dissolvable anhydrite from a similar reservoir formation as used in the study by Yousef et al.,10 with a special focus on the relationship between the concentration of SO42− and NaCl present in the low saline brine.

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EXPERIMENTAL SECTION

Materials. Core Material. Preserved reservoir limestone cores from a formation in the Middle East were used in the study. All cores were sealed and protected from exposure to air. No distinct visible fractures or heterogeneities were detected by visual inspection of the core surface. The core properties are listed in Table 1. The permeability was in the range of 50 mD for all cores.

Table 1. Core Properties of Preserved Reservoir Limestone Cores core no.

L, cm

D, cm

porosity, %

permeability, mD

1 2 3

4.7 4.2 4.2

3.8 3.8 3.8

28 27 23

51

Crude Oil. Stock tank crude oil from the same reservoir as the core material was used. Prior to use, the oil was centrifuged and filtered through a 5 μm Millipore filter to remove sediments and water. The acid and base numbers (AN and BN) were measured by potentiometric titration using a Mettler Toledo DL55 autotitrator. The methods used have been developed by Fan and Buckley and are modified versions of the standard methods ASTM D664 for AN titration and ASTM D2896 for BN titration.13−15 The crude oil properties are given in Table 2. Brines. The synthetic brines were made using deionized (DI) water and reagent grade salts. All brines were filtered through a 0.22 μm Millipore filter and vacuumed to reduce dissolved air prior to use. The compositions of the different brines are listed in Table 3. FW0S is sulfate-free formation water with high salinity, 213000 ppm, containing high concentrations of Ca2+ and Mg2+. By dilution of this brine 100 times, the salinity of d100FW0S is reduced to 2130 ppm. GSW is Persian/Arabic Gulf seawater with a total salinity of 57760 ppm. GSW0Na is GSW depleted in NaCl giving a salinity of 16570 ppm. GSW was diluted 10 and 30 times, giving the brines termed d10GSW and d30GSW, respectively, with salinities of 5776 and 1860 ppm.

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RESULTS Verification of Anhydrite in the Reservoir Core. The preserved core no. 1 was mildly cleaned, saturated with 100% FW0S, and aged for 3 days at 100 °C in the core holder. Then the core was flooded with DI water at a rate of 1.0 PV/D, and effluent samples were collected. The samples were analyzed for Ca2+, Mg2+, and SO42−, Figure 1. After 4 PVs were injected, the concentration of Ca2+ and SO42− stabilized close to 10 mM. The SO42− concentration remained constant during the whole test, with a total of 55 PVs injected. With equal concentrations of Ca2+ and SO42− in the effluent, this must be related to dissolution of anhydrite, CaSO4(s). The contribution to Ca2+ by dissolution of calcite is small. The Mg2+ concentration

METHODS

Core Preparation. Mild Cleaning. Prior to core restoration, all cores were mildly cleaned to remove reservoir fluids and preserve the core wetting. The core cleaning was performed in a Hassler core holder. To displace initial crude oil, the core was flooded with low aromatic kerosene until the effluent was transparent. Then the

Table 2. Crude Oil Properties AN, mg of KOH/g

BN, mg of KOH/g

asphaltene, g/(100 mL)

density, g/cm3 at 20 °C

viscosity, cP at 20 °C

0.15

0.84

2.54

0.8751

19.9

B

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Energy & Fuels Table 3. Brine Compositions FW0S, mM

d10FW0S, mM

d100FW0S, mM

GSW, mM

d10GSW, mM

d30GSW, mM

GSW0Na, mM

Na+ Ca2+ Mg2+ Cl− SO42− HCO3−

ions

2577.1 475.0 100.0 3721.1 0.0 6.0

257.7 47.5 10.0 372.1 0.0 0.6

25.8 4.7 1.0 37.2 0.0 0.1

797.5 16.0 86.0 909.5 45.0 2.0

79.8 1.6 8.6 91.0 4.5 0.2

26.6 0.5 2.9 30.3 1.5 0.1

92.0 16.0 86.0 204.0 45.0 2.0

TDS, g/L IS

213.00 4.30

21.30 0.43

2.13 0.04

57.76 1.15

5.78 0.11

1.93 0.04

16.53 0.44

Table 4. Rock Mineral Analyses by SEM/EDS on a Small Rock Sample element

wt %

at. %

Fe K Si Mg Ca

0.0 0.0 0.3 1.6 98.1

0.0 0.0 0.5 2.6 96.9

total

100.0

100.0

130 °C. The concentration of SO42− in the effluent was analyzed and plotted versus PV injected, Figure 3. As expected, the average concentration of SO42− increased as the temperature decreased, to 1.5, 2.8, and 3.4 mM at 130, 100, and 70 °C, respectively.

Figure 1. Core no. 1 100% saturated with FW0S, aged and flooded at a rate of 1 PV/D with DI water at 100 °C. Concentration of Ca2+, Mg2+, and SO42− in effluent samples vs PV injected.

decreased rapidly to well below 1 mM. The presence of Mg2+ can be related to the presence of some dolomite crystals in the matrix, as detected by the SEM/EDS analysis, Figure 2 and Table 4. The analysis indicated very pure calcite due to the high content of Ca, ≈97 at. %.

Figure 3. Core no. 1 100% saturated with FW0S, aged and flooded with FW0S at a rate of 10 PV/D. The test was performed at 70, 100, and 130 °C. Concentration of SO42− in the effluent vs PV injected.

Dissolution of Anhydrite vs Flooding Rate. To verify if a chemical equilibrium between rock and brine had been established during FW0S injection, core no. 1 was flooded at 1, 10, and 100 PV/D (0.01, 0.1, and 1 mL/min) at 130 °C. The SO42− concentration in the effluents was quite similar for all flooding rates, Figure 4. Thus, at 130 °C, a chemical equilibrium between anhydrite in the rock and FW0S appeared to have been established, since the concentration of sulfate is not depending on the contact time (flooding rate) between the rock and the flooding fluid. At lower temperatures, we may observe a difference in SO42− concentration at the different flooding rates since the chemical equilibrium is normally established much faster at higher temperatures.

Figure 2. SEM analyses of a reservoir limestone rock sample. The photograph taken with 200× magnification shows the presence of dolomite crystals.

Dissolution of Anhydrite vs Temperature. The presence of sulfate in the formation water, SO42−(aq), has a significant impact on the initial wetting condition in limestone.17 Therefore, it is important to quantify the dissolution of anhydrite in formation water, FW0S. Core no. 1 was saturated 100% with FW0S and flooded with FW0S at a rate of 1 PV/D (0.01 mL/min) at three different temperatures, 70, 100, and C

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Figure 4. Core no. 1 100% saturated with FW0S and flooded with FW0S at 130 °C. The flooding rates were 0.1, 1, and 10 PV/D. Concentration of SO42− in the effluent vs PV injected.

Figure 6. Oil recovery test at 100 °C on core no. 1. The core was successively flooded with FW0S and d100FW0S with an injection rate of 1 PV/D. Oil recovery (% of OOIP) is plotted vs PV injected.

Seawater Depleted in NaCl as a “Smarter” EOR Fluid. The reservoir cores no. 2 and no. 3 were restored and mounted as a composite core in a Hassler core holder for oil recovery test at 100 °C. The cores were successively flooded at a rate of 0.6 PV/D (0.01 mL/min) with FW0S, GSW, and GSW0Na, Figure 5. During FW0S injection, ∼21% of OOIP was

recovery. The mobilization of the extra oil is, however, a slow process, and a large number of PVs had to be injected to reach the oil recovery plateau. The response time appeared to be system dependent; i.e., it may vary from case to case. The same core, core no. 1, was mildly cleaned, and then the dissolution of anhydrite during FW0S and d100FW0S injection was tested at 100 °C. The concentrations of Ca2+ and SO42− in the effluent samples were determined, Figure 7. Note that the

Figure 5. Oil recovery test at 100 °C from the composite core, core no. 2 and core no. 3. The composite core was successively flooded with FW0S, GSW, and GSW0Na with an injection rate of 0.01 mL/ min (≈0.6 PV/D). Oil recovery (% of OOIP) is plotted vs PV injected.

Figure 7. Core no. 1 100% saturated and flooded with FW0S and d100FW0S at 100 °C. The flooding rate was 1 PV/D. Concentration of Ca2+ and SO42− in the effluent vs PV injected.

produced. By switching to GSW in a tertiary mode, the oil recovery increased to ∼27% of OOIP. Finally the flooding brine was changed to GSW0Na (GSW depleted in NaCl, but containing the same concentration of the important potential determining ions, Ca2+, Mg2+, and SO42−). The oil recovery increased to ∼32% of OOIP, confirming that a decrease in the NaCl concentration improved the efficiency of GSW to act as a “smarter” EOR fluid. Tertiary Low Salinity EOR Effect by Injecting Formation Water. The restored core no. 1 was used in an oil recovery test at reservoir temperature at 100 °C to verify any LS EOR effect by injecting d100FW0S in tertiary mode after FW0S injection. The injection rate was kept constant at 1 PV/ D (0.01 mL/min), Figure 6. About 25% of OOIP was produced during FW0S injection. A drastic increase in the oil recovery was obtained by switching to d100FW0S. The oil recovery increased to ∼47% of OOIP, i.e., nearly a doubling of the

FW0S was free of SO42−. The difference in the concentrations of SO42− in FW0S and d100FW0S is of great interest, because SO42− acts as a catalyst for the wettability alteration process. The concentration of SO42− increased from 2.8 mM in FW0S to 5.3 mM in d100FW0S, i.e., nearly by a factor of 2, and combined with a 100 times decrease in the concentration of NaCl, more oil is recovered due to improved wettability alteration.7,8 Low Salinity EOR effect by Injecting Diluted Seawater. For offshore carbonate oil reservoirs, seawater will be the natural injection fluid. Seawater itself is a smart wettability modifying brine containing all of the active ions needed to improve the water wetness. Provided that dissolvable anhydrite is available in the pore space, diluted seawater can act as an improved wettability modifier. Two series of experiments were performed: D

DOI: 10.1021/acs.energyfuels.5b01099 Energy Fuels XXXX, XXX, XXX−XXX

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Energy & Fuels In the first test series, core no. 1 was restored for a new oil recovery test. Core no. 1 was successively flooded at a rate of 1 PV/D with FW0S, GSW, and d10GSW at 100 °C, Figure 8.

Figure 10. Two oil recovery tests at 100 °C on core no. 1 with an injection rate of 1 PV/D. The flooding sequence was FW0S−d10GSW in the first, and FW0S−d30GSW in the second recovery test. Oil recovery (% of OOIP) is plotted vs PV injected. Switching of fluids is indicated by the dashed lines. Figure 8. Oil recovery test at 100 °C on core no. 1. The core was successively flooded with FW0S−GSW−d10GSW with an injection rate of 1 PV/D. Oil recovery (% of OOIP) is plotted vs PV injected.

when using d30GSW compared to d10GSW, i.e., by about 5% of OOIP using d10GSW to about 18% of OOIP using d30GSW. Produced water samples were collected during the oil recovery tests, and the concentrations of Ca2+ and SO42− were analyzed, Figures 11 and 12. In the first test, the

About 25% of OOIP was recovered during the secondary mode with FW0S, which is similar to the previous test shown in Figure 6. The oil recovery increased to ∼30% of OOIP by a tertiary flood with GSW. In the final step using d10GSW, the oil recovery reached ∼33% of OOIP corresponding to ∼10% extra oil. After a mild core cleaning, the dissolution of anhydrite in d10GSW was tested by flooding the core at 100 °C, Figure 9. The initial concentrations of Ca2+ and SO42− in d10GSW were 1.6 and 4.5 mM, respectively. The concentrations of both ions in the effluent increased to ∼10 mM.

Figure 11. Chemical analysis of the produced water samples during the oil recovery test at 100 °C on core no. 1. The flooding sequence was FW0S−d10GSW with an injection rate of 1 PV/D. The concentrations of Ca2+ and SO42− in the effluent are plotted vs PV injected.

Figure 9. Core no. 1 100% saturated and flooded with d10GSW at 100 °C. The flooding rate was 1 PV/D. Concentration of Ca2+ and SO42− in the effluent and in d10GSW vs PV injected.

concentration of SO42− during FW0S injection stabilized at ∼2 mM, Figure 11, while it increased to ∼8 mM with d10GSW, which is higher than the initial concentration of SO42− present in d10GSW, 4.5 mM. The concentrations of Ca2+ and SO42− approached each other, which confirmed dissolution of anhydrite. In the second test, Figure 12, the concentration of SO42− in the effluent during d30GSW injection stabilized at ∼4 mM, which is about half of the concentration observed in the effluent during d10GSW injection. The LS EOR effect increased, however, from an extra 5 to 18% of OOIP, even though the concentration of the catalyst for the wettability alteration process decreased. This result can be related to the difference in the NaCl concentrations in the two cases, as seen in earlier work.7,8

In the second test series, core no. 1 was restored for two new oil recovery tests at 100 °C. The objective of the tests was to observe the low salinity effect in relation to the concentration of SO42− and NaCl in the effluent. The flooding sequences for the two cases were as follows: (1) FW0S followed by d10GSW; (2) FW0S followed by d30GSW. Both recovery tests were performed with a rate of 1 PV/D. The results are shown in Figure 10. The oil recovery by FW0S was 18 and 16% of OOIP, which was somewhat lower than that observed previously, Figures 6 and 8. The LS EOR effect increased dramatically E

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concentration remained constant during 55 PVs being injected, confirming the presence of dissolvable anhydrite. The same core no. 1 was tested for tertiary low salinity EOR effects by flooding first with high salinity FW0S (213000 ppm) and then with 100 times diluted FW0S (2130 ppm). The oil recovery almost doubled, from 25 to 48% of OOIP, Figure 6. The wettability alteration is a slow process, and a large number of PVs had to be injected to reach the ultimate oil recovery plateau. In a separate test, the dissolution of anhydrite in FW0S and d100FW0S was compared at the reservoir temperature, 100 °C. The dissolution of anhydrite increased from 2.8 mM in FW0S to 5.3 mM in the diluted FW0S, Figure 7. Thus, by decreasing the salinity, especially the concentration of Ca2+ (from 475 to 4.75 mM) and that of the inactive salt NaCl (from 2580 to 25.8 mM), the concentration of SO42− increased due to increased solubility of anhydrite. Increased SO42− concentration has a dramatic effect on the oil recovery in a forced displacement process.7,8 In order to understand the chemical mechanism for the observed low salinity effect in carbonates, the impact of temperature and brine composition/salinity on the following equilibrium must be understood:

Figure 12. Chemical analysis of the produced water samples during the oil recovery test at 100 °C on core no. 1. The flooding sequence was FW0S−d30GSW with an injection rate of 1 PV/D. The concentrations of Ca2+ and SO42− in the effluent are plotted vs PV injected.

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DISCUSSION The key ion for SW to act as a wettability modifier in carbonates is SO42−, which acts as a catalyst for the desorption of polar organic carboxylic species from the carbonate surface. Normally, the concentration of SO42− in the formation water is low due to a high concentration of Ca2+. The solubility of anhydrite, CaSO4(s), in pure water is moderate at low temperatures, 2.01 g/L at 20 °C, and it decreases as the temperature increases, 1.62 g/L at 100 °C. In formation water with high Ca2+ concentration, the dissolution is reduced due to the common ion effect. The chemical mechanism for wettability alteration in carbonates, which involves the active ions Ca2+, Mg2+, and SO42−, has been discussed in detail previously, and so far no experimental contradictions to the suggested mechanism have been observed.6,17 If seawater is depleted in the inactive ions, Na+ and Cl−, the efficiency as a wettability modifying fluid toward carbonates increases compared to ordinary seawater.9 An increase in oil recovery of about 10% of OOIP was observed in a spontaneous imbibition process in chalk at 90 °C.7 It was suggested that the access of the active ions Ca2+, Mg2+, and SO42− toward the calcite surface was improved if the ionic double layer close to the surface was depleted in inactive ions such as Na+ and Cl−. This was also verified in Figure 5, when GSW depleted in NaCl increased the oil recovery by about 6% of OOIP after first flooding with GSW. The chemical induced wettability alteration process is sensitive to temperature, and the efficiency increases with increasing temperature. The surface reactivity of SO42− and Ca2+ at the carbonate surface also increases as the temperature increases, and desorption of carboxylic material becomes more efficient.18 Regarding oil recovery, it has also been shown that a decrease in temperature can be compensated for by an increase in the SO42− concentration of the imbibing fluid.19 Provided that reasonable amounts of Ca2+ and/or Mg2+ are present, both the concentration of NaCl and SO42−(aq) in the injected brine will have significant effects on the wettability alteration process at a given temperature. If SO42− is not present in the injection fluid, dissolution of anhydrite, CaSO4(s), can act as an in situ source of SO42− if present in the formation. The core material in this study contained anhydrite as shown by the test on core no. 1, Figure 1. During injection of DI water, the effluent contained equal amounts of Ca2+ and SO42−, ∼9 mM, and the

CaSO4 (s) ↔ Ca 2 +(aq) + SO4 2 −(aq) ↔ Ca 2 +(ad) + SO4 2 −(ad)

(1)

Ca2+(aq) and SO42−(aq) are ions dissolved in the pore water, and Ca2+ (ad) and SO42− (ad) are ions adsorbed onto the carbonate surface. In a previous work, the impact of SO42− on the initial wetting condition was studied, and the concentration of SO42−(aq) appeared to be the key factor determining the initial wetting properties.17 Dissolution of anhydrite, CaSO4(s), which in this case is the source for SO42−(aq), is dependent on the salinity and composition of the brine and on temperature in several ways: (1) The solubility increases as the concentration of Ca2+ in formation water decreases (common ion effect); (2) the solubility decreases as the NaCl concentration decreases (complex formation between Ca2+ and Cl−); (3) the solubility decreases as the temperature increases; (4) the concentration of SO42−(aq) may also decrease as the temperature is increased due to increased adsorption onto the carbonate surface, i.e., the concentration of SO42−(ad) increases.18 The efficiency of the wettability alteration process is also affected by temperature and salinity:7−9,19 (1) the efficiency increases as the temperature increases. A decrease in efficiency of the wettability alteration process at lower temperatures (80− 90 °C) can partly be compensated for by increasing the SO42− concentration. (2) The efficiency increases as the concentration of SO42− in the injected fluid increases, as it is the catalyst for the wettability alteration process. (3) The efficiency increases as the concentration of inactive salt, NaCl, in the injected brine decreases. The decrease in the solubility of anhydrite as the temperature increases was verified by flooding the limestone core no. 1 with FW0S at 70, 100, and 130 °C. The concentrations of SO42− in the effluents were determined to be 3.4, 2.8, and 1.5 mM, respectively, Figure 3. At 130 °C, a chemical equilibrium between the brine and rock appeared to have been established, since no significant difference in the concentration of SO42− in the effluent samples was observed, by increasing the flooding rate by a factor of 100, Figure 4. F

DOI: 10.1021/acs.energyfuels.5b01099 Energy Fuels XXXX, XXX, XXX−XXX

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Energy & Fuels

Table 5. Relationship between Extra Oil Produced at 100 °C, Effluent Concentration of SO42− and Initial NaCl Concentration under Tertiary Brine Injection Using d100FW0S, GSW, d10GSW, and d30GSW after Secondary Waterflooding with FW0S

Thus, the effects of temperature and concentration of NaCl are in conflict; i.e., the concentration of SO42−(aq) decreases as the temperature increases, while the surface reactivity leading to the wettability alteration increases as the temperature increases. Similarly, the concentration of SO42−(aq) decreases as the amount of NaCl decreases, but the surface reactivity promoting wettability alteration increases. Therefore, for a carbonate system there appears to be an optimum temperature window for observing maximum LS EOR effect. The OLI Systems Stream Analyzer 3.2 software was used to evaluate the dissolution of anhydrite when exposed to FW0S (213000 ppm), d10FW0S (21300 ppm), and d100FW0S (2130 ppm) as a function of temperature. The decrease in solubility of anhydrite in FW0S as the temperature increased was much smaller compared to that in both 10 times and 100 times diluted FW0S, Figure 13. It is also interesting to note that the

extra oil, % OOIP SO42, mM NaCl, mM salinity, ppm

FW0S

d100FW0S

GSW

d10GSW

d30GSW

2.8 2580 213000

22 5.3 25.8 2130

5 10 796 57760

5 7.5 79.6 5776

18 4 26.6 1925

mM was the main factor responsible for the increase in extra oil. The separate impact on the EOR effect by changing the concentration of sulfate or NaCl has recently been published,9 and it was observed that the EOR effect increased significantly when increasing the sulfate concentration or decreasing the concentration of NaCl. The EOR effect by removing NaCl from GSW while keeping the concentration of sulfate constant is also demonstrated in Figure 5. By comparing the extra oil in Figures 8 and 10, it is quite obvious that the amount of extra oil decreased as the SO42− concentration in the effluent decreased. Remember that SO42− acts as a catalyst for the wettability alteration process in the presence of Ca2+ and Mg2+ and that the rate of the wettability alteration process surely decreases as the concentration of SO42− decreases. Simulated values for the dissolution of anhydrite in GSW, d10GSW, and d30GSW versus temperature are presented in Figure 14. In a bulk solution, anhydrite appears to precipitate

Figure 13. Simulated dissolution of CaSO4(s) when exposed to FW0S and 10× and 100× diluted FW0S as a function of temperature.

dissolution of anhydrite is quite similar in d10FW0S and d100FW0S. The simulated value of the solubility of anhydrite at 100 °C in d100FW0S is very close to the experimental value, 5.3 mM, shown in Figure 7. The simulated solubility in FW0S is, however, significantly higher than the experimental value, ∼4 compared to 2.8 mM, respectively. At high temperatures, >120 °C, the concentration of SO42− becomes quite similar for the different brines. Thus, the difference in the potential for wettability alteration must be mostly related to the salinity effect, i.e., the decrease in NaCl concentration. In offshore oil reservoirs, seawater is the actual injection fluid to improve oil recovery. Seawater itself is a smart EOR fluid, which can enhance oil recovery by wettability modification as illustrated in Figure 8. Flooding with d10GSW improved the oil recovery by 3% of OOIP after flooding first with GSW. Yousef et al.10 observed the greatest kick in oil recovery when using 20 times diluted seawater. Two different oil recovery tests were performed on the same Core#1, using FW0S as injection fluid in a secondary mode, and d10GSW or d30GSW in a tertiary mode, Figure 10. The extra oil produced in the tertiary flood using GSW, d10GSW and d30GSW, as well as the effluent concentrations of SO42− and NaCl is summarized in Table 5. The extra oil recovered by GSW and d10GSW were quite similar, ∼5% of OOIP. A huge EOR effect of ∼18% of OOIP was obtained by using d30GSW. Even though the concentration of SO42− in the effluent was reduced from 7.5 to 4 mM compared to d10GSW, it appeared that the decrease in the NaCl concentration from 79.6 to 26.6

Figure 14. Simulated dissolution of CaSO4(s) when exposed to SW and 10× and 30× diluted SW as a function of temperature.

from GSW at T > 100 °C. The conditions in a porous medium may, however, be different. The dissolution of anhydrite in d10GSW and d30GSW at 100 °C is close to 10 mM, which is in the range of the measured concentrations observed in Figures 11 and 12. The SO42− concentration of 45 mM in GSW is about 3 times higher than the concentration of Ca2+ (16 mM), Table 3. The effluent concentration of Ca2+ and SO42− when core no. 1 was flooded with d10GSW at 100 °C was quite similar, slightly below 10 mM, Figures 9 and 11. Thus, a significant amount of anhydrite was dissolved even though d10 GSW already contained 4.5 mM of SO42−. The largest tertiary LS EOR effect was observed for d100FW0S and d30GSW, 22 and 18% of OOIP, respectively, G

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Energy & Fuels

(4) When using FW0S and d100FW0S in a secondary and tertiary flood, a low salinity EOR effect of ∼22% of OOIP, or an increase in oil recovery of 88%, was observed. (5) When flooding the core successively with FW0S, GSW, and d10GSW, a stepwise increase in oil recovery was observed; 25, 30, and 33% of OOIP. (6) When using FW0S and d10GSW in a secondary and tertiary oil recovery test, the tertiary LS EOR-effect was 18% of OOIP. (7) A low salinity EOR effect can be obtained in carbonates containing anhydrite. The chemical mechanism is in principle the same as that reported previously for seawater, but in this case, an extra supply of sulfate to the brine was obtained by dissolution of anhydrite. (8) The low salinity EOR technique can have a great economical potential in high temperature (T > 90 °C) carbonate reservoirs containing a significant amount of dissolvable anhydrite distributed in the pore space.

Table 5. It is consistent that the parameters affecting the LS EOR effect, i.e., the concentrations of SO42− and NaCl and the total salinity, were quite similar in the two cases, 5.3 and 25.8 mM and 2130 ppm for d100FW0S and 4 and 26.6 mM and 1925 ppm for d30GSW, respectively, Table 5. Outcrop chalk cores, completely free from anhydrite, responded oppositely in a spontaneous imbibition process, when seawater (33000 ppm) was diluted 20 times to 1600 ppm. The recovery decreased from 61 to 17% of OOIP, respectively.7 As seawater was diluted, the concentration of the active ions decreased, and no supplement of SO42− was obtained due to the absence of anhydrite in the pores. This confirms that anhydrite must be present in situ in order to observe EOR effects by LS water flooding in carbonates.12 To summarize, the chemical mechanism for LS EOR effect in carbonates is in principle the same as that published previously for seawater.6 The only difference is that the carbonate rock must contain a SO42− source, i.e., anhydrite. Sulfate dissolved in the pore water, SO42−(aq), acts as a catalyst in the wettability alteration process. Injection of the LS brine caused the concentration of SO42−(aq) in the brine to increase due to increased dissolution of anhydrite. In addition, the reduced concentration of NaCl in the brine increased the efficiency of the wettability alteration process.7 The LS EOR effect observed by Pu et al.11 in sandstone cores with very low clay content, but with significant amounts of dolomite and anhydrite, could be explained in the same way by assuming that dolomite behaves like limestone toward the active ions Ca2+, Mg2+, and SO42−. In a spontaneous imbibition process, both reservoir dolomite cores containing anhydrite and outcrop dolomite cores without anhydrite responded positively when 10 times diluted SW was used as imbibing fluid compared to ordinary seawater.20 Thus, the relative importance of the active ions to achieve wettability modification is different for dolomite and limestone, which will be discussed in a forthcoming report. It has also been reported that dolomite acted similarly to limestone when cationic surfactant was used as a wettability modifier.21

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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 We are thankful to Saudi Aramco for financial support and for providing reservoir oil and core material.

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REFERENCES

(1) Loahardjo, N.; Xie, X.; Yin, P.; Morrow, N. R. Low salinity waterflooding of a reservoir rock. International Symposium of the Society of Core Analysts, Calgary, Canada, Sep. 10−12, 2007, Paper SCA200729. (2) Lager, A.; Webb, K. J.; Black, C. J. J. Impact of brine chemistry on oil recovery. 14th European Symposium on Improved Oil Recovery, Cairo, Egypt, Apr. 22−24, 2007, Paper A24. (3) Lager, A.; Webb, K. J.; Collins, I. R.; Richmond, D. M. LoSal enhanced oil recovery: Evidence of enhanced oil recovery at the reservoir scale. 2008 SPE/DOE Improved Oil Recovery Symposium, Tulsa, OK, USA, Apr. 19−23, 2008, Paper SPE 113976. (4) Austad, T.; RezaeiDoust, A.; Puntervold, T.Chemical mechanism of low salinity water flooding in sandstone reservoirs. 2010 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, USA, Apr. 24−28, 2010Paper SPE 129767 . (5) RezaeiDoust, A.; Puntervold, T.; Austad, T. Energy Fuels 2011, 25, 2151−2162. (6) Zhang, P.; Tweheyo, M. T.; Austad, T. Colloids Surf., A 2007, 301, 199−208. (7) Fathi, S. J.; Austad, T.; Strand, S. Energy Fuels 2010, 24, 2514− 2519. (8) Fathi, S. J.; Austad, T.; Strand, S. Energy Fuels 2011, 25, 5173− 5179. (9) Puntervold, T.; Strand, S.; Ellouz, R.; Austad, T. J. Pet. Sci. Eng. 2015, 133, 440−443. (10) Yousef, A. A.; Al-Saleh, S.; Al-Kaabi, A.; Al-Jawfi, M. Laboratory investigation of novel oil recovery method for carbonate reservoirs. Canadian Unconventional Resources & International Petroleum Conference, Calgary, Canada, Oct. 19−21, 2010, Paper CSUG/SPE 137634MS; Society of Petroleum Engineers: Richardson, TX, USA, 2010; DOI: 10.2118/137634-MS. (11) Pu, H.; Xie, X.; Yin, P.; Morrow, N. R. Application of coalbed methane water to oil recovery by low salinity waterflooding. 2008 SPE Improved Oil Recovery Symposium, Tulsa, OK, USA, Apr. 19−23, 2008, Paper SPE 113410.

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CONCLUSIONS Previously, Yousef et al.10 have reported an increase in oil recovery from limestone cores by using diluted seawater as injection fluid. Similar studies using outcrop chalk free from anhydrite have shown opposite oil recovery effects when introducing diluted seawater.7 In this present study, core material from a reservoir formation similar to that used by Yousef et al.10 was tested with the objective to improve the chemical understanding of the mechanism for LS EOR effects in carbonate. The following conclusions can be drawn: (1) The reservoir carbonate cores contained a significant amount of anhydrite, CaSO4(s), which acted as an in situ source of sulfate, which is known to act as a catalyst for the wettability alteration process using seawater. (2) The dissolution of anhydrite increased as the flooding fluid was switched from a high saline to a low saline fluid, resulting in increased concentration of the active catalyst, SO42−, in the flooding fluid. (3) The efficiency of the low salinity wettability alteration process at a given temperature is mostly related to the concentration of sulfate and to the decrease in the NaCl concentration of the brine. H

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Energy & Fuels (12) Austad, T.; Shariatpanahi, S. F.; Strand, S.; Black, C. J. J.; Webb, K. J. Energy Fuels 2012, 26 (1), 569−575. (13) ASTM2896-88 Standard test method for base number of petroleum products by potentiometric perchloric acid titration. Annual Book of ASTM Standards; American Society for Testing Materials: Philadelphia, PA, USA, 1988. (14) ASTM664-89 Standard test method for acid number of petroleum products by potentiometric titration. Annual Book of ASTM Standards; American Society for Testing Materials: Philadelphia, PA, USA, 1989. (15) Fan, T.; Buckley, J. SPE J. 2007, 12, 496−500. (16) Springer, N.; Korsbech, U.; Aage, H. K. Resistivity index measurement without the porous plate: A desaturation technique based on evaporation produces uniform water saturation profiles and more reliable results for tight North Sea chalk. International Symposium of the Society of Core Analysts, Pau, France, Sep. 21−24, 2003. (17) Shariatpanahi, S. F.; Strand, S.; Austad, T. Energy Fuels 2011, 25 (7), 3021−3028. (18) Strand, S.; Høgnesen, E. J.; Austad, T. Colloids Surf., A 2006, 275, 1−10. (19) Zhang, P.; Austad, T. Colloids Surf., A 2006, 279, 179−187. (20) Romanuka, J.; Hofman, J.; Ligthelm, D. J.; Suijkerbuijk, B.; Marcelis, F.; Oedai, S.; Brussee, N.; Linde, H. v. d.; Aksulu, H.; Austad, T. Low salinity EOR in carbonates. 18th SPE Improved Oil Recovery Symposium, Tulsa, OK, USA, Apr. 14−18, 2012, Paper SPE 153869; Society of Petroleum Engineers: Richardson, TX, USA, 2012; DOI: 10.2118/153869-MS. (21) Standnes, D. C.; Nogaret, L. A. D.; Chen, H.-L.; Austad, T. Energy Fuels 2002, 16 (6), 1557−1564.

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DOI: 10.1021/acs.energyfuels.5b01099 Energy Fuels XXXX, XXX, XXX−XXX