Favorable Temperature Gradient for Maximum Low-Salinity Enhanced

Publication Date (Web): April 26, 2017 ... SO42– are key ions in the Smart Water wettability alteration process in limestone and that low-salinity (...
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Favorable Temperature Gradient for Maximum Low-Salinity Enhanced Oil Recovery Effects in Carbonates S. Strand, S. C. Henningsen, T. Puntervold,* and T. Austad University of Stavanger, 4036 Stavanger, Norway ABSTRACT: Experimentally, it has been found that Ca2+ and SO42− are key ions in the Smart Water wettability alteration process in limestone and that low-salinity (LS) enhanced oil recovery (EOR) effects in limestone can be observed if the formation minerals also include dissolvable anhydrite, CaSO4. A diluted brine, such as a standard LS brine, contains low amounts of Ca2+ and SO42−, which prevent wettability alteration from taking place. However, if the formation contains anhydrite mineral, Ca2+ and SO42− are supplied to the injection brine through dissolution, and in that case, a standard LS brine can cause wettability alteration in a limestone reservoir. A tertiary LS EOR effect of 22% original oil in place was observed at 100 °C during viscous flooding of 100 times diluted formation water in a limestone reservoir core containing anhydrite. Anhydrite dissolution and precipitation is dependent upon the temperature, and the solubility of anhydrite in water decreases as the temperature increases. In this paper, the importance of a temperature gradient during water flooding of a limestone oil reservoir containing anhydrite, for obtaining maximum LS EOR effects, was addressed. Such a temperature gradient was experimentally simulated by flooding the LS brine through two cores, one at room temperature and the other at the actual reservoir temperatures, varying from 40 to 130 °C. As a result of a decrease in anhydrite dissolution with increasing temperatures, the concentrations of Ca2+ and SO42− increased beyond the expected solubility range at the tested temperatures. The LS EOR effect is very much linked to the concentration of sulfate, the catalyst for the wettability alteration process in carbonates. Therefore, a temperature gradient during water flooding of a limestone reservoir containing anhydrite will have a positive effect on the LS EOR process because the concentrations of the most important Smart Water ions, Ca2+ and SO42−, are at the maximum all of the time.

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INTRODUCTION Water-based enhanced oil recovery (EOR) by wettability modification has great potential, especially in carbonates, and much work has been published using seawater (SW) as the wettability modifier at high temperatures.1 Parametric studies have shown that a symbiotic interaction between the potential determining ions Ca2+ and SO42− at the carbonate surface are able to release negatively charged polar organic material from the positively charged rock surface and SO42− appeared to act as a catalyst for the process.2,3 Carboxylic material, which can be quantified by the acid number (AN, mg of KOH/g) in the crude oil, is believed to act as anchor molecules for creating mixed wet conditions.4 The efficiency of SW as a wettability modifier in a spontaneous imbibition process can increase remarkably by removing NaCl from the injection fluid.5−7 It was suggested that the presence of large amounts of Na+ and Cl− in the ionic double layer outside the positively charged carbonate surface partly prevented the access of the active ions SO42− and Ca2+ to the surface. It was also observed that SW depleted in NaCl and spiked with extra SO42− increases the oil recovery dramatically compared to ordinary SW, especially in the lower temperature range, 90 °C.6,7 It is well-known that low-salinity (LS) EOR effects can be observed in sandstone under specific conditions.8−10 Similar EOR effects have also been observed in limestone by diluting SW.11 The chemical understanding of the mechanism for the LS EOR effect in carbonate and sandstone is, however, completely different.3,5,6,10,12,13 The LS EOR effect in limestone can be observed under forced displacement provided that the rock contains a dissolvable source of sulfate, normally anhydrite, CaSO4.13,14 The amount of NaCl in the LS brine © XXXX American Chemical Society

is low, and the injected LS brine will be enriched in important potential-determining ions, such as Ca2+ and especially SO42−, from the formation. The success for wettability alteration mostly depends upon the concentration of SO42−.3 In a tertiary water flood with LS brine, the microscopic sweep efficiency can be improved by increasing the water wetness of bypassed pores during the secondary water flooding. A new bank of oil is mobilized through spontaneous imbibition into bypassed oilcontaining pores. The water wetness of the total porous system will then increase, causing increased capillary trapping of oil. If, however, the amount of oil mobilized by improved sweep efficiency is larger than the oil trapped by increased water wetness, a net LS EOR effect will be observed. Dissolution of anhydrite, CaSO4, has normally a negative temperature profile; i.e., the dissolution decreases as the temperature increases. This can be a great advantage in a reservoir field situation. LS water injection will reduce the reservoir temperature close to the injector, and the temperature will then increase toward the producing well. The amount of SO42− present in the LS brine as it moves toward the production well should then be at a maximum or even supersaturated at the actual reservoir temperature. This temperature gradient is the scope addressed in this paper. LS brine was flooded through two cores containing dissolvable anhydrite connected in series: the first core at a low temperature, simulating near injection well conditions, and Received: November 14, 2016 Revised: April 3, 2017

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DOI: 10.1021/acs.energyfuels.6b03019 Energy Fuels XXXX, XXX, XXX−XXX

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During core cleaning of La 2 and La 3, the cores were flooded with DI water at room temperature. Effluent samples were analyzed for concentrations of Ca2+ and SO42−. Core Restoration. The mildly cleaned core La 1 was restored, first by establishing initial water saturation (Swi) of 10% FW by the desiccator technique.15 After Swi = 10% was obtained, the core was kept in a sealed container for 3 days to obtain a uniform ion distribution throughout the core. The core was then saturated and flooded with the crude oil, 2 PV in both directions at 50 °C. Finally, the core was surrounded by crude oil and aged in a pressurized container at reservoir temperature for 2 weeks. Oil Recovery Test. The restored core La 1 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 at reservoir temperature, 100 °C, by successively flooding the core with FW followed by d100FW at a constant rate of 0.01 mL/min (∼1 PV/day). The produced liquids were collected in a graded buret, and the cumulative oil production was measured with an accuracy of ±0.1 mL. Oil recovery as percent original oil in place (OOIP) was plotted against PV of brine injected. The reservoir core material used in these experiments is similar to that previously used in oil recovery experiments by Yousef et al.11 and Austad et al.,13 which all showed LS EOR effects. Only one oil recovery experiment has been presented in this paper, but the reproducibility of the EOR effect for this core material has been documented previously in the above-mentioned studies. Temperature Gradient Test for Dissolution of Anhydrite. The experimental setup for simulating the temperature gradient for the dissolution of anhydrite when injecting LS EOR brine into limestone reservoir cores containing dissolvable anhydrite is shown in Figure 1. The first core, La 2, was kept at ambient temperature, 22 °C, while the second core, La 3, was placed in a heating chamber at a constant temperature varying from 40 to 130 °C in the individual experiments. The setup is flexible, allowing flooding of each of the cores separately as well as in combination. A series of tests were performed using the same cores. Experiments were performed at 40, 70, 90, 110, and 130 °C. In each test, both cores were initially flooded with d100FW, La 2 at 22 °C, and La 3 at the specific temperature. The concentration of Ca2+ and SO42− in the effluent was monitored, and the value stabilized after about 3 PVs injected. After 5.4 PV, the flooding of La 3 continued using the effluent from La 2 at 22 °C as the injection fluid, enriched with dissolved anhydrite, Ca2+ and SO42−. The concentration of Ca2+ and SO42− in the effluents was analyzed as a function of the pore volume injected. Analyses. Scanning Electron Microscopy (SEM) and EnergyDispersive X-ray Spectroscopy (EDS) Microanalysis. A Zeiss Supra 35VP field emission microscope equipped with an energy-dispersive spectrometer 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 alumina stub. A thin platinum layer was applied to avoid charging of the samples. Ion Concentrations. Chemical analyses of the water samples were performed on an ICS-3000 reagent-free ion chromatograph produced by Dionex Corporation, Sunnyvale, CA, U.S.A. Effluent samples were diluted 10−1000 times before analyses, and the ionic concentrations of Ca2+, Mg2+, and SO42− were calculated on the basis of external standards. Good repeatability of the ion concentrations was confirmed better than ±3%. Brine Modeling. 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 minerals in d100FW was modeled at constant temperatures from 30 to 140 °C. An excess amount of CaSO4 (s) was equilibrated with d100FW, and the concentrations of sulfate in the brine were modeled at the various temperatures. Precipitation was modeled by adding 8.5 mM, which is approximately the concentration of sulfate dissolved in d100FW at 22 °C, to the d100FW brine and then obtaining the amount of CaSO4 (s) forming at the various temperatures.

the second core at temperatures between 40 and 130 °C, simulating in-depth reservoir conditions. The SO42− concentration at the outlet of the high-temperature core was monitored and compared to the sulfate concentration obtained by bypassing the low-temperature core.

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EXPERIMENTAL SECTION

Materials. Oil. A stabilized crude oil was used with properties given in Table 1.

Table 1. Physical and Chemical Properties of Reservoir Crude Oil AN (mg of KOH/g)

BN (mg of KOH/g)

asphaltenes (g/100 mL)

density at 20 °C (g/cm3)

viscosity at 20 °C (mPa s)

0.15

0.84

2.54

0.8751

19.9

Brines. The synthetic formation water (FW) without sulfate was prepared using deionized (DI) water and reagent-grade salts. The solution was filtered through a 0.22 μm Millipore filter and evacuated to remove dissolved air. The properties of FW and 100 times diluted FW, d100FW, are listed in Table 2.

Table 2. Chemical Composition and Properties of Brines ion

FW (mM)

d100FW (mM)

Na+ Ca2+ Mg2+ Cl− HCO3− SO42− TDS (g/L) IS

2580 475.0 100.0 3725 6.0 0.0 213.0 4.303

25.80 4.75 1.00 37.25 0.06 0.0 2.13 0.043

Core Preparations. Core Cleaning. Three reservoir limestone cores were used in this experimental study. Core La 1 was used for an oil recovery test, and La 2 and La 3 were used to study the temperature gradient for the dissolution of anhydrite. The initially preserved core La 1 was mildly cleaned with kerosene, n-heptane, and DI water to maintain the initial wetting condition of the core as good as possible. Kerosene was injected at a rate of 0.1 mL/min until the effluent was transparent, followed by n-heptane to displace the kerosene. Then, 3 pore volumes (PV) of DI water were injected to remove FW and easily dissolvable salts. Cores La 2 and La 3 were cleaned by flooding the cores with toluene, methanol, and DI water. The cores were dried at 90 °C to a constant weight. Core properties are given in Table 3.

Table 3. Properties of Reservoir Limestone Cores core

length (cm)

diameter (cm)

porosity (%)

permeability (mD)

remarks

La 1 La 2 La 3

4.7 4.8 4.9

3.8 3.8 3.8

28.0 15.3 11.9

51 277 298

preserved cleaned cleaned

Verification of Anhydrite Minerals, CaSO4 (s). The presence of anhydrite minerals in the reservoir limestone cores was confirmed in core flooding tests using DI water. After the oil recovery test, core La 1 was cleaned and dried. Then, the core was evacuated, saturated with FW, and aged at reservoir temperature, 100 °C, for 3 days in a Hassler core holder with a confining pressure of 20 bar and with a back pressure of 10 bar. Finally, DI water was injected at 0.1 mL/min, and effluent samples were collected and analyzed for concentrations of Ca2+, Mg2+, and SO42−. B

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Figure 1. Schematic model of the flooding setup used to study the temperature gradient effect for core material containing anhydrite. Core La 2 (to the left) is flooded at ambient temperature (22 °C), and core La 3 (to the right) is flooded at various temperatures from 40 to 130 °C.

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RESULTS AND DISCUSSION As mentioned in the Introduction, to observe LS EOR effects in limestone, the formation must contain dissolvable anhydrite, which is a common mineral in carbonate reservoirs. It was experimentally verified that the presence of SO42− in the FW affects the initial wettability in limestone reservoir cores and also in chalk cores.16,17 In limestone containing anhydrite, a LS water injection will promote dissolution of Ca2+ and SO42−, which are the ions responsible for wettability alteration, and a LS EOR effect can be observed. For limestone reservoirs subjected to surfactant-assisted alkaline flooding with Na2CO3, the presence of dissolvable anhydrite is bad, because the anhydrite dissolution contributes with Ca2+ ions. The injected CO32− ions will then precipitate as CaCO3 and prevent the propagation of alkalinity through the reservoir.18 In previous work studying the chemical mechanism for wettability alteration using SW as an EOR fluid, it was observed that the oil recovery by spontaneous imbibition increased from 10 to 50% of OOIP as the concentration of SO42− increased from 0 to 4× the sulfate concentration present in ordinary SW.19 Similar experiments showed that that increasing the concentration of Ca2+ in the imbibing SW also improved the oil recovery significantly at a constant concentration of SO42−.3 Therefore, dissolution of anhydrite, CaSO4, will increase the concentration of both Ca2+ and SO42− in the LS injection brine and must have an impact on oil recovery by wettability alteration in carbonates. This section is organized in the following way: (1) both selected reservoir limestone cores were tested for dissolvable anhydrite; (2) the tertiary LS EOR effect was confirmed by an oil recovery test using core La 1; and (3) temperature gradient effects on the dissolution of anhydrite were discussed at different temperatures. Presence of Dissolvable Anhydrite in Reservoir Limestone Cores. Often, EDS analysis on rock samples does not detect elemental sulfur, as shown in Table 4 for a rock piece taken from core La 1. The concentration of sulfur from anhydrite could be below the detection limit for the EDS detector, but even small amounts of anhydrite present as pore minerals can contribute with significant amounts of Ca2+ and SO42− ions dissolved into the injection brine. To confirm the presence of anhydrite minerals that could contribute in a Smart Water EOR process, reservoir cores should be flooded with distilled water and any presence of Ca2+ and SO42− should be monitored in the effluent.

Table 4. EDS Analysis of a Representative Porous Rock Sample from Core La 1 element

wt %

atomic %

Ca Mg Al Si K Fe S total

98.1 1.6 0.0 0.3 0.0 0.0 0.0 100.0

96.9 2.6 0.0 0.5 0.0 0.0 0.0 100.0

The amount of dissolvable sulfate available from core La 1 was determined after the oil recovery test (described in the following section) had been performed. Core La 1 was mildly cleaned, dried, then 100% saturated with FW, and aged at the reservoir temperature, 100 °C, in the core holder. When the core was flooded at 100 °C with DI water and the ions eluted were monitored (Figure 2), it was seen that the concentration of Ca2+ and SO42− remained quite constant, in the range of 8− 10 mM, for more than 50 PV injected. Similarly, dissolution of anhydrite also took place in core La 2 and La 3 during DI water flooding at ambient temperature, as shown by Figures 3 and 4. After 6 PV injected, the

Figure 2. Concentration profiles of Ca2+, Mg2+, and SO42− when core La 1 was flooded with DI water. Initially, the core was saturated and aged with FW. The core was flooded at 100 °C with a rate of 0.1 mL/ min. C

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Energy & Fuels concentration of Ca2+ and SO42− was in the range of 8 mM in both cores.

Figure 5. Oil recovery test at 100 °C by forced displacement in core La 1. The core was restored with Swi = 0.1 of FW, saturated, flooded, and aged in crude oil. The experiment was performed by successively flooding FW−d100FW at a constant injection rate of 1 PV/day.

Figure 3. Concentration profiles of Ca2+ and SO42− in the effluent during DI water flooding of core La 2 at ambient temperature. The injection rate was 1.0 PV/day (0.02 mL/min).

dissolution enriched the d100FW brine with Ca2+ and SO42− coming from the formation. When the FW is diluted 100 times, also the concentration of non-active ions Na+ and Cl− in the ionic double layer close to the positively charged rock surface is reduced drastically, as discussed previously.5−7 Because sulfate acts as the catalyst for the wettability alteration, a maximum amount of sulfate in the LS brine will both speed up and maximize the EOR process. The solubility of anhydrite increased as the temperature decreased, and this effect could contribute with an increased sulfate concentration in the LS EOR brine sweeping through the reservoir when cold injection water cools the reservoir close to the injector. The temperature gradient effect on the concentration of sulfate was investigated and is discussed in the next section. Temperature Gradient Effects on Anhydrite Dissolution. During water injection, cold surface water is pumped into the reservoir. A temperature gradient in the reservoir close to the injectors develops over time. The temperature gradient effect on anhydrite dissolution has been experimentally investigated. The experimental setup is shown in Figure 1, involving two core holders with the possibility to flood the cores individually or in series. A series of tests were performed with the same cores, starting at 40 °C. In each test, both cores were initially flooded with d100FW, La 2 at 22 °C and La 3 at the specific temperature. After 5.4 PV, the flooding of La 3 continued using the effluent from La 2 at 22 °C as the injection fluid. This injection fluid was d100FW enriched with dissolved Ca2+ and SO42−. A typical plot of the effluent concentration of Ca2+ and SO42− from core La 3 versus PV injected at 90 °C is shown in Figure 6. For each temperature gradient test, the concentration of SO42− eluting from La 2 at 22 °C at 5.4 PV injected was determined and confirmed constant and equal to 8.5 mM, represented by the red stippled arrow. The initial Ca2+ concentration of 4.7 mM in the d100FW brine is also included as the blue stippled arrow in Figure 6. As expected, the concentration of Ca2+ and SO42− in the effluent from La 3 at 90 °C increased when the LS brine having passed through the low-temperature core La 2 was injected into core La 3. The concentrations were significantly higher compared to direct flooding of core La 3 with d100FW. The temperature gradient significantly increased the concentration

Figure 4. Concentration profiles of Ca2+ and SO42− in the effluent during DI water flooding of core La 3 at ambient temperature. The injection rate was 1.0 PV/day (0.02 mL/min).

Oil Recovery Test with the Tertiary LS EOR Effect. After core cleaning and restoration of the preserved core La 1, an oil recovery test at 100 °C was performed by successively flooding FW followed by d100FW. The flooding rate was constant and equal to 1 PV/day (Figure 5). A recovery plateau of 25% OOIP was reached after 3 days of injection with FW. After 4 days, the injection fluid was changed to d100FW, which is a LS brine without SO42−. A drastic increase in oil recovery was observed during d100FW injection. The oil recovery increased to 47% OOIP, nearly a doubling of the recovery. The mobilization of the extra oil was, however, a slow process, and 20 PV had to be injected to reach the recovery plateau. End effects may be a problem in oil recovery from small cores during viscous flooding. The large and steady increase in oil recovery when switching from FW to dilute FW cannot be linked to end effects only. Furthermore, Yousef et al.11 did not observe any significant end effects in their composite core of the same material as in the present study, when switching from high-salinity to LS injection fluid. In comparison to oil recovery using FW as displacing fluid in secondary mode, a very large LS EOR effect was obtained, even though no SO42− was present in the injection brine. Anhydrite D

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Figure 8. Dynamic equilibrated SO42− concentration eluted from the core La 3 during d100FW injection at different conditions: (1) green curve, eluted SO42− concentration from core La 3 during the serial flooding of core La 2 at ambient temperature (aT) followed by La 3 at increasing temperatures of 40, 70, 90, 110, and 130 °C; (2) red curve, SO42− from La 3 at increasing temperatures (bypassing La 2); and (3) blue stippled curve, SO42− eluted from core La 2 at ambient temperature. The flooding rate was constant and equal to ∼1.0 PV/ day.

Figure 6. Concentration profiles of Ca2+ and SO42− in the effluent when flooding La 3 at 90 °C. First, d100FW was injected into La 3, and then after 5.4 PV, the injection fluid was switched to d100FW effluent from core La 2 at ambient temperature (aT). The injection rates was constant and equal to ∼1 PV/day.

of active ions Ca2+ and SO42− in the eluted brine, which could contribute with increased oil recovery and a positive Smart Water EOR effect. The temperature gradient results are summarized in Figure 7. At all temperatures, except at 70 °C, a significant increase in the

remarkable difference in the sulfate concentration when the flooding condition was performed with a temperature gradient or not. At 100 °C, the increase in the SO42− concentration was about 60% (Figure 8). Thus, it appeared that the LS brine in the high-temperature core La 3 was supersaturated concerning anhydrite and that thermodynamic equilibrium was established as the temperature approached 130 °C. A thermodynamic model, provided by OLI Systems stream analyzer 3.2, was used to calculate anhydrite dissolution in the LS brine d100FW as a function of the temperature (blue stippled line in Figure 9). The experimental data for the sulfate concentration eluted from La 3 without a temperature gradient are also included (red curve). Except for the low-temperature case at 40 °C, the fit was remarkably good. This low experimental value for anhydrite dissolution may be due to kinetic effects, i.e., with lower dissolution rate at lower

Figure 7. Effluent SO42− concentration profiles during core flooding of La 3 at different temperatures. Initially, d100FW was injected into La 3, and after 5.4 PV injected, the injection fluid was switched to the La 2 (enriched d100FW) effluent. The injection rate was constant and equal to 1 PV/day.

SO42− concentration was observed. Knowing that the solubility of anhydrite decreases as the temperature increases, it is reasonable to believe that the LS brine in the high-temperature core La 3 became supersaturated with regard to anhydrite dissolution. In Figure 8, the SO42− concentration (average concentration after 7−8.5 PV injected) eluted from La 3 after exposed to the temperature gradient is plotted versus the test temperature (green curve). From Figure 7, the average SO42− concentration between 3 and 5 PV injected was calculated and plotted in Figure 8 as the red curve, representing anhydrite dissolution without any temperature gradient. This should be the equilibrium concentrations at the given temperatures provided that thermodynamic equilibrium was obtained during flooding. It is interesting to note that, between 70 and 130 °C, there is a

Figure 9. Anhydrite dissolution in d100FW brine at varying temperatures. (1) Simulated values using OLI Systems stream analyzer 3.2 (stippled blue curve) and (2) experimental data for the equilibrated dissolution of anhydrite from core La 3 during injection of d100FW at 40, 70, 90, 110, and 130 °C (red curve). Anhydrite dissolution is equal to the concentration of SO42−. E

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CONCLUSION LS EOR effects in reservoir limestone systems at higher temperatures are possible if the pore surface minerals contain dissolvable anhydrite. Low concentrations of non-active ions, Na+ and Cl−, and an enrichment of Ca2+ and SO42− in the LS brine as a result of anhydrite dissolution are the main reason for promoting wettability alteration and LS Smart Water EOR effects. The results from this experimental study are shortly summarized in the following way: (1) A tertiary LS EOR effect of about 25% OOIP was observed at 100 °C in a forced displacement using 100 times diluted FW as a LS brine. (2) A dissolvable sulfate content of 8−10 mM was observed when flooding the cores with distilled water at ambient temperature. (3) It was experimentally verified that the solubility of anhydrite decreased with increasing temperatures. (4) As a result of the decreasing solubility of anhydrite with increasing temperatures, the amount of important and active Smart Water ions, Ca2+ and SO42−, in the LS brine decreased with an increase in the temperature. (5) A temperature gradient in a reservoir during water flooding could have a positive effect on the LS EOR process, because the concentration of the most active ions in the wettability alteration process, Ca2+ and SO42−, propagating into the reservoir is at the maximum all of the time. (6) The concentration of sulfate in the LS brine increased significantly as the temperature gradient increased from 22 °C to actual reservoir temperatures, and the brine behaved supersaturated in the temperature range of 90−130 °C.

temperatures. The time that the surface minerals were exposed to the LS injection brine was probably too short to achieve dissolution equilibrium at 40 °C, as shown in Figure 9. Therefore, the increase in the sulfate concentration in the second stage must be related to dissolution of anhydrite and not to supersaturation. This is supported by the simulated and experimental values of the sulfate concentration at 70 °C. At this temperature, equilibrium in the dissolution of anhydrite must have been just established and the sulfate concentrations became similar in the two stages. At 90, 100, and 110 °C, the concentration of sulfate in the second stage became supersaturated, and at 130 °C, precipitation of anhydrite must have taken place, causing similar concentrations of sulfate in the two stages. No increase in the inlet pressure was observed during the test. From Figure 8, the supersaturation of anhydrite was at the highest around 100 °C. From a reservoir point of view, an interesting question is “How deep into the reservoir could this supersaturated LS brine propagate?” This is of course difficult to verify experimentally in the laboratory using small cores. In an actual field situation, the water front will be well ahead of the temperature gradient front. A significant part of the wettability alteration will probably take place at the water front, and it is, therefore, uncertain to what extent the temperature gradient will affect the LS EOR effect by dissolution of anhydrite. In the low-temperature region, the dissolution of anhydrite is at its highest and a certain amount of anhydrite will dissolve. As the temperature increases, the brine can be supersaturated or saturated with anhydrite. A further increase in the temperature will cause precipitation to reach a new chemical equilibrium in dissolved anhydrite at the actual temperature. As such, as a result of the temperature gradient during the waterflood, the brine should have a maximum content of dissolved anhydrite and maximum concentration of Ca2+ and SO42− at any reservoir temperature, irrespective of the size of the cooling region, provided that the flow rate is low enough to allow for complete CaSO4 saturation of the injection brine. As shown by Figure 8, supersaturation depended upon the temperature, even for the small core used this test. At the temperatures of 90, 100, and 110 °C, supersaturation was observed, but at 130 °C, no supersaturation was observed because of fast precipitation of anhydrite, CaSO4. A combined geochemical and reservoir modeling approach could maybe give some information about the extent of supersaturation on the reservoir scale. By combining the tests at different temperatures, one can picture how the concentration of sulfate could vary under a continuous temperature gradient in the reservoir from 22 to 130 °C. As a result of a longer contact time between the LS injection fluid and the rock, kinetic effects due to the dissolution rate of anhydrite will only be observed at a low temperature close to the injector. Equilibrium in the dissolution of anhydrite will be established, and the concentration of Ca2+ and SO42− will be at the maximum and even supersaturated, as the injected LS brine moves toward higher temperatures. However, no supersaturation will be observed at high temperatures, as shown by the test at 130 °C. A temperature gradient causing increased concentrations of the Smart Water EOR ions has been experimentally verified in a limestone reservoir containing dissolvable anhydrite. Higher concentrations of Ca2+ and SO42− in the LS injection brine will have a positive LS Smart Water EOR effect.

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AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. ORCID

T. Puntervold: 0000-0002-5944-7275 Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The authors thank Saudi Aramco for providing relevant reservoir limestone core material containing anhydrite.

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REFERENCES

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DOI: 10.1021/acs.energyfuels.6b03019 Energy Fuels XXXX, XXX, XXX−XXX