Coupling Smart Seawater Flooding and CO2 Flooding for

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Coupling Smart Seawater Flooding and CO2 Flooding for Sandstone Reservoirs; Smart Seawater-Alternating-CO2 Flooding (SMSW-AGF) Hasan Naeem Al-Saedi, Yifu Long, Ralph E. Flori, and Baojun Bai Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b02289 • Publication Date (Web): 03 Sep 2019 Downloaded from pubs.acs.org on September 3, 2019

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Coupling Smart Seawater Flooding and CO2 Flooding for Sandstone Reservoirs; Smart Seawater-Alternating-CO2 Flooding (SMSW-AGF) Hasan N. Al-Saedi a, b, Yifu Long a, Ralph E. Flori a, Baojun Bai a a

b

Department of Geosciences and Geological and Petroleum Engineering, Missouri University of Science and Technology, Rolla, Missouri, 65409, United States Iraqi Ministry of Oil, Missan Oil Company, Amara, Missan 62001, Iraq

Abstract Petroleum engineers continue to seek cost-effective improved oil recovery (IOR) methods to increase recovery efficiency, especially in heavy oil accumulations. Currently, smart water, low salinity (LS) water, and CO2 are the most economically viable IOR methods according to the abundance of the resources. The purpose of this work is to flood Bartlesville sandstone cores saturated with heavy oil successively with seawater, “smart” seawater, and finally CO2 with the aim of obtaining an optimum combination of these relatively low cost methods. The core-flood experiments achieved promising results that could inform traditional EOR methods for heavy oil. Several core-flooding scenarios were run, but the optimum scenario was 8 PV’s of seawater, 8 PV’s of smart seawater with depleted Ca2+ and 10 PV’s of miscible CO2. The seawater alone produced only ~20% of OOIP, the smart seawater produced an additional 12.9% of OOIP, and the final miscible CO2 step produced 64.52% of OOIP, for a total of 96.77% of OOIP. There appears to be a synergistic effect of these methods. Other cases investigated also incorporated one low salinity (LS) water and three “smart” seawater cases. When injecting LS water instead of smart seawater, the total oil recovery was slightly lower than that of the smart seawater case. We found that the significant oil recovery was due to the LS water effect, not from the synergic effect of LS water and CO2. This conclusion is based on the solubility of CO2 in LS water being higher than that in smart seawater, which redirects CO2 to dissolve in the heavy crude oil and results in increased oil recovery. Using the same brines’ composition that were used in the core-flood experiments, contact angle measurements and spontaneous imbibition tests on the same core materials were performed. The results of contact angle and spontaneous imbibition confirmed a wettability alteration of the rock surface towards more water-wet using our new EOR process. This combination technology can mitigate the CO2 flooding problems (gravity override, viscous channeling, and early breakthrough) and improve CO2 sweep efficiency by incorporating smart seawater, which itself has the ability to increase oil recovery by altering the wettability towards more water-wet and by reducing the solubility of CO2 in the injected water, which redirects it to heavy crude oil.

1. Introduction Eastern Kansas oil fields contain heavy oil that is produced via sucker rod pumps. The daily production from the Bartlesville Sandstone Reservoir is around 500 bbl/day with high water cut. The Bartlesville Sandstone Reservoir is shallow (900 ft depth) with a low reservoir temperature (25°C). Normally, shallow reservoirs contain vast quantities of heavy oil worldwide that make the temperature of these formations typically low.

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Such reservoirs have a low temperature and an oil viscosity of several hundred centipoises. The best solution to such a reservoir is thermal EOR techniques to ease heavy oil flow by reducing its viscosity, such as steam flooding and steam-assisted gravity drainage (SAGD). However, thermal methods are not always the best solution due to the problems associated with thermal processes, such as cost of generating steam, steam override, and channeling. The water alternating steam process (WASP) was one of the most useful solutions for overcoming the steam problems. WASP reduces or eliminates steam breakthrough because water that is injected after steam causes the steam zone to collapse while tending to pass the reservoir. In turn, more vertical thermal fronts are formed1. In addition, we developed a new method of coupling steam with low salinity water flooding to avoid the aforementioned steam flooding problems2, 3. However, steam flooding is still an expensive and environmentally unfriendly source of improved oil recovery (IOR)4. Water flooding is an inexpensive EOR method. Low salinity and smart water are excellent candidates to alter the sandstone water wetness. It has been experimentally proven that it is not the lower salinity of the injected water that causes wettability alteration leading to increased oil recovery, but controlling the injected water chemistry triggers more sandstone water wetness5. To discriminate with low salinity water, smart water can be defined as water that is engineered by manipulating the ionic composition (adding/removing ions) regardless of the resulting salinity of the water. Low salinity water results from diluting several water resources such as formation water and seawater. Numerous mechanisms of low salinity water/smart water have been proposed, such as fines migration of clay particles with linked crude oil component6, pH increase 7, multi-component ion exchang8, mineral dissolution9, organic material desorption from the clay surface10, double layer expansion11, cation exchange on quartz surface12, and organic material desorption from quartz surface12. The aforementioned mechanisms could be combined and trigger the sandstone wettability towards more water-wet13-15. Gas injection, on the other hand, is another IOR method that significantly increases oil recovery. CO2 injection showed an impressive ability to enhance oil recovery16. Many types of CO2 projects have been presented, such as huff and puff, miscible and immiscible injection, and carbonated water flooding17. However, the sweep efficiency of the gas injection is weak in heavy oil. The mobility ratio is quite different between CO2 and the heavy oil, and if a conventional gas flooding is conducted, then the oil recovery could be low. Water-alternating-CO2 (WAG) was presented to overcome the mentioned gas injection problems17. The injected water in WAG is used to improve the sweep efficiency of the injected CO2; however, the possibility of injected water alternating wettability was overlooked in the literature until coupled CO2 LSWAG was presented by Dang et al. (2014)18 followed by the extensive work conducted by Teklu et al. (2015, 2015b, and 2016)19-21. Seawater (SW) has always been used secondarily and tertiarily after reducing its salinity. In some oil fields (especially offshore), it is easy to utilize seawater as the available water source. Technical and economic difficulties will be encountered in diluting the seawater to below 5000 ppm to obtain low salinity water, knowing that active ions are more feasible to utilize than seawater in tertiary EOR. To our knowledge, no study utilizes seawater as smart water (keeping the same seawater salinity) and combines it with CO2 injection. Smart seawater alternating gas flooding (SMSW-AGF) is a novel combination EOR method was coupled due to the vital role of each method in increasing oil recovery, and it showed an impressive result in enhancing oil recovery. The ability of CO2 to increase oil recovery was tested, and the oil recovery increased by improved wettability alteration towards more water-wet and interfacial tension reduction. Although CO2 improved oil recovery, the density difference between CO2 and oil raised gravity segregation21, viscous fingering, and early breakthrough22. For that reason, we developed smart seawater 2 ACS Paragon Plus Environment

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alternating CO2 flooding in order to gather the benefits of smart water (wettability alteration) and to improve the sweep efficiency of CO2 while preventing CO2 problems mentioned earlier as well as utilizing the benefits of CO2 in increasing oil recovery by swelling the oil, reducing oil viscosity, and triggering wettability of the rock towards water-wet.

2. Methodology 2.1. Materials 2.1.1. Reservoir cores. Colt Energy Inc provided preserved Bartlesville Sandstone Reservoir cores. The cores were all taken from the same depth. The mineralogical properties of the cores are quite similar. The reservoir core properties for these used in minimum miscibility pressure (MMP) are given in Table 1 and for these used in other tests are shown in Table 3. Quartz was the primary mineral followed by clays, which were mostly illite and kaolinite. 2.1.2. Crude oil. The crude oil was provided by Colt Energy Inc. from the same formation as the preserved cores. The oil viscosity and density were ~600 cp and 0.83 gm/cc at 25°C, respectively. The total acid number and base number were 1.1 mg KOH/g and 1.83 mg KOH/g, respectively. 2.1.3. Brines. The chemicals were purchased from VWR. All chemicals used in this study are reagent grade. Milli-Q water was used to prepare the brines with a resistivity of 18.2 mΩ. cm. Synthetic formation water (FW) was prepared in the laboratory with total dissolved solids of 104,000 ppm. Synthetic seawater and SMSW were prepared using the same salts and water except for KCl. Six brines were used in this study including FW, SW, d10SW (LS water), SMSW1, SMSW2, and SMSW3. The smart waters were prepared by depleting the divalent cations/anions in the seawater, and the salinity of the SMSW was kept the same by substituting with NaCl. SW was diluted 10 times to obtain LS water of 5,140 ppm. The brines description is listed in Table 2 in millimole/L (mM).

2.2. Core preparations before core-flood experiments The cores were delivered fully saturated with oil and well coated with a plastic wrap. After the cores were cut to have a 1 in diameter, they were placed in a hassler core holder and were cleaned by a flooding process. Kerosene was injected into the core until a colorless effluent was obtained. Toluene was then injected followed by methanol. The cores were then flushed with low salinity water (4000 ppm NaCl) to displace methanol and for further FW and salts removal. The cores were cleaned with five cycles of toluene using Dean-Stark extractor. The cores were oven dried at 120℃ for 24 hrs to remove the residual water, after which the length (L), diameter (D), and dry weight (M) were measured. The cores were transferred to a vacuum container for evacuation purposes. A one-day vacuum was performed on all the cores, after which synthetic FW was presented in the cores under vacuum. The weight of the saturated core was measured to obtain the pore volume (PV) and porosity (φ). The core was mounted into the core holder and loaded with an overburden pressure that was 500-600 psi higher than the injection pressure. In the meantime, the environmental temperature was set at 50 ℃. FW was injected for connate water with four different flow rates (0.5, 1, 1.5, and 2 ml/min). Pressure transducers were employed to record the differential pressure (ΔP). Once the steady-state flow was established, the absolute permeability of the water phase (Kw) could be calculated via Darcy’s law. The FW was displaced by 5 pore volumes (PV) of crude oil from each direction to establish Swi at 50°C. The dead crude oil was injected with a flow rate of 0.25 ml/min until no water was produced and the pressure stabilized. While the produced fluid was collected, the Swi was


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calculated using the volume of produced water. The cores were then aged in the crude oil for five weeks at 90°C to restore the initial wettability.

2.3. Minimum miscibility pressure (MMP) As mentioned previously, the oil viscosity is 600 cp at ambient temperature. At the experiment conditions (50°C), the viscosity is 220 cp. The MMP procedure was performed as described by23. The schematic diagram of the high-pressure CO2 core-flood setup is depicted in Fig. 1. In the core-flooding experiments, the miscibility of CO2 was attained by adjusting the backpressure regulator to a pressure above the MMP. When miscibility is reached between the reservoir crude oil and the injected gas, an optimum residual oil mobilization will be obtained24, 25. Prior to the MMP tests, the reservoir cores were thoroughly cleaned the same way as described in the core preparation section. Five preserved reservoir cores were utilized for MMP measurements after core preparations were done as previously described. The core data and the MMP results are listed in Table 1. Five pressures were applied in these experiments with a ~300 psi difference between each pressure, starting at 1100 psi and ending at 2400 psi. As shown in Fig. 1, the MMP of Bartlesville Sandstone Reservoir cores and the same reservoir crude oil was calculated at 15.1 Mpa. To emphasize that the MMP was reached during core-flooding, backpressure of 2250 psi was applied. CO2 injection was terminated after a total of 2 PVs was injected and no more oil was produced. Three MMPs of 15.1, 15.65, and 17.15 MPa are determined by the linear extrapolation of the five coreflooding experiments shown in Table 1, which correspond to three high threshold oil recoveries of 88.24%, 90%, and 95%, respectively. It should be noted that the first threshold oil recovery of 88.24% is selected from the highest oil recovery obtained by core flooding as shown in Table 1. The MMP calculation is shown in Fig. 2.

2.4. Core flooding After the pre-aging duration was completed, the cores were then flooded with 8 pore volumes (PVs) of SW followed by 8 PVs of SMSW and 10 PVs of CO2 at 50°C. SW and SMSW were injected into the cores until no more oil was produced and the pressure stabilized. The flow rate was 0.5 ml/min and the confining pressure did not exceed 600 psi over the injection pressure. The backpressure was also set at 2250 psi. The reservoir cores were flooded using the following scenarios: 1. RC8a was flooded with CO2 only. 2. RC8b was flooded with SW followed by CO2. 3. RC8c was flooded with SW followed by SMSW1 and CO2. 4. RC8d was flooded with SW followed by SMSW2 and CO2. 5. RC8e was flooded with SW followed by SMSW3 and CO2. 6. RC8f was flooded with SW followed by LS water and CO2. The CO2 injection followed SW flooding in Tests #2-6; however, SW flooding was not performed in Test#1, which was designed as a control test. In SW flooding, 8 PVs were injected while the flow rate was kept at 0.5 ml/min. A digital video camera was used to record the cumulative volume of the produced oil. Smart seawater (SMSW) flooding or LS water flooding was carried out after SW flooding in Test #3-6; however, LS water flooding was not performed in Test#2 as it was designed as a comparison test. In SMSW and LS water flooding, 8 PVs were injected while the flow rate was kept at 0.5 ml/min. In CO2 flooding, the confining pressure was first increased to 800 psi higher than the injection pressure. The backpressure regulator pressure was set at 2250 psi to ensure miscibility, and the systemic pressure was then built up through the circulation line. In CO2 flooding, 10 PVs were injected while the flow rate was kept at 0.5 ml/min. 4 ACS Paragon Plus Environment

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Fig. 1. Schematic diagram of core-flooding experimental system.

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80 ORF2 =90%, MMP2 = 15.65 MPa

70 60

ORF3 =95%, MMP3= 17.15 MPa

(R² = 0.9614) ORF = 3.4418Pinj + 36.061 50 6

8

10

12

14

16

18

Pressure, MPa Fig. 2. Minimum miscibility pressure calculated from core flooding using linear extrapolation.


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Table 1 Core data and MMP test results Core # D, cm L, cm K, md RC A 6.02 5.09 RC B 6.1 1.0 RC C 2.54 5.92 1.7 RC D 5.85 3.08 RC E 6.1 1.96

φ, % 13.88 14.0 14.28 15.03 17.0

Soi, % 72.8 74.1 77.14 76.32 72.48

Injection Pressure, psi 1100 1400 1800 2100 2400

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Oil recovery factor, % 63.0 69.48 81.25 84.85 88.24

2.5. Contact angle measurements The contact angle was determined by Ramé-hart advanced goniometer 500-F1. The test was conducted at 50°C. The dry cut reservoir sandstone substrate was smoothed with fine sandpaper to attain a smooth core face. The substrates were cleaned with toluene and then rinsed with deionized water and left to dry overnight in the oven at 80°C. After the drying process, the substrates were aged in crude oil for five weeks at 90°C to restore initial wettability as described in core-flood experiments. The oil droplet was initiated beneath the substrate, and the contact angle was measured. The equilibrium time was set at 30 minutes. The contact angle was measured for both brine, and carbonated brines. The schematic of the testing setup is shown in Fig. A in the supporting information.

2.6. Spontaneous imbibition In order to test our theory, wettability must be presented as evidence. Spontaneous imbibition using Amott cells was carried out to identify the wettability of the sandstone cores; SW, SMSW1, SMSW2, SMSW3, and LS water were used as imbibed fluids in the Amott cells. Another five cores were cleaned and restored as described previously. The imbibition test lasts for 100 days because of the high viscosity of the crude oil. The spontaneous imbibition was conducted inside the oven at the same temperature as the core-flooding, which is 50°C.

2.7. Measurements of pH The pH measurements were taken for every 3-5 ml of the aqueous samples. The samples were collected by the fraction collector. The calibration of the apparatus was done by using three buffers (4, 7, and 14). The Symphony B10P pH meter from VWR was used to measure the pH. The pH of FW and LS water before flooding were 7.6 and 7.08, respectively.

2.8. Theory of the proposed study In this study, we propose a novel EOR process by emerging SMSW and CO2 flood for a heavy oil sandstone reservoir. This combined EOR process increases heavy oil recovery as a result of synergistically utilizing the improved oil recovery mechanisms of the two EOR methods. We claim that 1. 2. 3.

SMSW triggers wettability alteration of the sandstone towards more water-wet. CO2 promotes oil swelling, reduction in oil viscosity, and triggers wettability alteration, causing it to become more water-wet and lowering IFT. Coupling LS water with CO2 was firstly presented by Dang et al. (2014)18. In this study, we believe that controlling ions (i.e., smartening the injected water) has more EOR effects and is more feasible. 6 ACS Paragon Plus Environment

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4.

5.

WAG is the most frequently applied EOR process because it improves sweep efficiency17, 26, 27. Therefore, combining SMSW with CO improved the sweep efficiency in addition to the 2 benefits of the SMSW in altering the wettability towards more water-wet. The solubility of CO2 in SMSW is less than the solubility in LS water, so the undissolved CO2 will bypass to crude oil and result in increased oil recovery.

Table 2 Ion composition and total dissolved solids of brines used in the oil recovery experiments, contact angle, and imbibition tests (mM). Compound

FW

SW

LSW (d10SW)

SMSW1 (0Na2SO4)

SMSW2 (0MgCl2)

SMSW3 (0CaCl2)

NaCl CaCl2 MgCl2 Na2SO4 KCl TDS (mg/L)

1386 153.2 52.5

530.4 18 141.8 34.5

53.04 1.8 14.18 3.45

614.3 18 141.8 0

761.43 18 0 34.5

564.65 0 141.8 34.5

51,400

5140

51,400

51,400

51,400

Table 3 Core data. Core # RC8a RC8b RC8c RC8d RC8e RC8f RC9a RC9b RC9c RC9d RC9e

13.4 104,000

D, cm

2.54

L, cm 5.615 5.6 6 5.921 5.851 6.171 4.4 4.25 4.36 4.53 4.55

K, md 3.56 2.72 5.2 1.43 2.3 3.72 2.37 0.6 1.15 0.72 1.68

φ, % 16.47 16.69 14.14 14.0 14.18 16.08 13.58 11.5 12.43 13.74 15.45

PV, ml 4.686 4.734 4.3 4.197 4.204 5.026 3.027 2.46 2.747 3.035 3.56

Type of test Core flooding and contact angle test

Imbibition test

Fluid type CO2 only SW + CO2 SW + SMSW1 + CO2 SW + SMSW2 + CO2 SW + SMSW3 + CO2 SW + LSW + CO2 SW SMSW1 SMSW2 SMSW3 LS

3. Results and Discussion The main mechanism of oil recovery by CO2 injection is the dissolution of CO2 in the oil, the resultant oil viscosity reduction, and oil swelling.

3.1. Scenario#1: CO2 injection Three conditions were specified by Sohrabi and Emadi (2012) for CO2 injection: (1) Crude oil must be used (refined oil will not work), (2) Waterflood must be performed before CO2 injection (in this scenario, we are evaluating this condition)28. Water acts as a membrane between oil and the injected CO2, which could help in CO2 diffusing from water to oil28. Adverse observations were shown by Campbell et al. (1985) 29. Campbell explained that when CO2 was injected after water flooding, CO2 will not be able to reach the trapped oil ganglia because of the water layers configured around the oil during water flooding (this will be 7 ACS Paragon Plus Environment

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evaluated in the upcoming scenarios), and (3) CO2 must not present as a vapor because vapor has a lower diffusion into oil other than liquefy or supercritical CO2. The viscosity difference between CO2 and high viscous oil prompts a low displacement efficiency. This viscosity difference led CO2 to viscous fingering inside the heavy oil. CO2 was injected in with a flow rate of 0.5 ml/min. No oil recovery was observed in the first 0.3 injected PVs. Thereafter, the oil was seen flowing out the core. An early CO2 breakthrough was observed, which was after injecting slightly more than 0.5 PVs. This early breakthrough can be ascribed to the density difference between the injected CO2 and the in situ heavy crude oil. The early breakthrough also could be due to the mobility ratio since there is a big difference in viscosities of CO2 and heavy oil. The early breakthrough occurred because of the inherent CO2 sweep limitations. The gravity override prompted CO2 to jump over the oil bank. Not all CO2 flow out the cores was due to breaking through. The evidence for this is the continuous oil production until 1.5 PVs of CO2 were injected after the breakthrough point (marked in red in Fig. 3). The total oil recovery was 78.58% of the OOIP. The CO2 injection was terminated after injecting 6 PVs because no oil recovery was observed in the last 4 injected PVs. The pressure drop across this core was also plotted against injected PV amount. The pressure drop increased dramatically at the injection beginning and dropped quickly until it stabilized at less than 1 psi. The gas injection encountered no restriction which explained the low pressure, especially at the last 4 PVs. It is worth mentioning that after breakthrough, the production of oil can be ascribed to the viscous forces, CO2 dissolution in crude oil, light and intermediate component extraction from the crude oil, and methane liberation22. The methane liberation increased oil viscosity, but CO2 dissolution in crude oil leads to a decrease in oil viscosity. A small amount of CO2 can reduce oil viscosity30. It is evident that oil was produced after breakthrough because of the dissolution of a small portion of CO2 inside crude oil even after breakthrough.

3.2. Scenario#2: SW flooding prior CO2 injection In this experiment, RC8b was allotted for core flooding. Previously31, we did an experimental study to inject FW prior to CO2 flooding, and the result of oil recovery was higher than when we injected CO2 alone. That experiment was conducted under immiscible conditions. In this experiment, miscible CO2 flooding was carried out after SW flooding. The total injected SW PVs were 16 PVs followed by 10 PVs of miscible CO2. We injected 16 PVs of SW to reduce the uncertainty of the results due to injected pore volumes and to make them equal to the experiments in the next experiments (consistency). In this and the following experiments, 10 PVs of CO2 were injected.


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ΔP, psi

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Oil Recovery, %

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400

20

0

0 0

2

4

6

Injected Pore Volume Fig. 3. Oil recovery factor and pressure drop as a function of the injected PVs of CO2 for RC8a.

The results of the oil recovery and pressure drop are shown in Fig. 4. The oil recovery increased dramatically in the first injected PV of SW, the water breakthrough before injecting 1 PV of SW. After that, the oil recovery increased slowly until no more oil recovery was observed when a complete 3 PVs were injected. The oil recovery curve remained at 23.33% of the OOIP until the entire 16 PVs of SW were injected. The water flooding at this point was terminated. The pressure profile (as can be seen in Fig. 4) increased dramatically until it reached the plateau at 1116 psi. Since then, and due to the density differences between CO2 and crude oil, the pressure profile decreased noticeably and gradually until stabilizing at the end of CO2 flooding at 2.4 psi. More than 1 PV of the CO2 were injected and no oil recovery was observed. Thereafter, the oil recovery was witnessed increasingly from 17.3 injected PVs to 24.5 PVs of the injected CO2. The oil recovery due to miscible CO2 was 63.34%, making the total oil recovery from this experiment about 86.67% of the OOIP. Recall the oil viscosity is 600 cP, which reduced to 220 cP at the experiment temperature (50°C). This high oil recovery from a heavy oil reservoir is exceedingly tremendous.


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P, psi

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400

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5

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Injected Pore Volume Fig. 4. Oil recovery factor and pressure drop as a function of the injected PVs of SW and CO2 for RC8b.

3.3. Smartening seawater In the following experiments, we aimed to modify SW to enhance the performance of the injected SW prior to CO2 injection so that they can compound with CO2 to recover more heavy oil. Three brines were prepared out of SW –SMSW1, SMSW2, and SMSW3– which are smart seawater brines where Na2SO4, MgCl2, and CaCl2 were entirely depleted in SW, respectively, while keeping salinity the same by adding NaCl. The SMSWs were depleted from the mentioned chemicals by not adding them to the brines.

3.3.1. Scenario#3: SW + SMSW1 + CO2 In this experiment, SW was injected in secondary recovery mode followed with SMSW1 and CO2 in tertiary mode. This was conducted with the purpose of changing the porous media properties such as altering sandstone wettability and also increasing the solubility of the CO2 in the crude oil other than dissolve in the injected SW. Additional water was flooded after SW and before CO2. This additional water is SMSW1. As mentioned previously, the salinity of SMSW brines was similar to SW salinity, but the composition was different. SMSW1 was depleted in Na2SO4. We believe that modifying SW composition could increase oil recovery by altering sandstone wettability and reduce the solubility of CO2 in the water. The solubility reduction in water is favorable since CO2 will be more soluble in crude oil, which is desirable. The oil recovery after injecting 8 PVs of SW was 31.25% of the OOIP. Upon switching to SMSW1, the oil recovery increased to 46.88% of the OOIP. The pressure drop during SW and SMSW1 remained constant all the way until SMSW1 flooding terminated after injecting 8 PVs of SMSW1. The pressure drop decreased rapidly during CO2 flooding due to its low density. The oil recovery during 10 PVs of CO2 flooding was 43.75% of the OOIP. The total oil recovery from this experiment was 90.63% of the OOIP. The results of core flooding and pressure drop across RC8c are shown in Fig. 5.


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40

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ΔP, psi

Oil Recovery, %

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ΔP 400

20

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0 0

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Injected Pore Volume Fig. 5. Oil recovery factor and pressure drop as a function of the injected PVs of SW, SMSW1, and CO2 for RC8c.

3.3.2. Scenario#4: SW + SMSW2 + CO2 In this experiment, the core-flooding procedure was conducted the same way as in the previous experiment. The fluids were injected by 8 PVs of both SW and SMSW2 and 10 PVs of CO2. SMSW2 salinity was the same as SW, but MgCl2 was depleted when salinity was kept at 51,400 ppm. The oil recovery during SW flooding was 32.26% of the OOIP. Injecting 8 PVs of SMSW2 provided an additional 22.58% of the OOIP. CO2 flooding resulted in 33.87% of the OOIP, which was lower than that improved by scenario#3 (33.87 vs. 43.75%). The total oil recovery from this experiment was 88.7% of the OOIP. The same behavior of pressure drop was observed (high at water flooding and low at CO2 flooding) except for during SMSW2, where the pressure continued to increase, due to fines migration because of the absence of Mg2+. Fines migration was observed by the naked eye. Fig. 6 shows the results of this experiment.


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CO₂ ΔP

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Injected Pore Volume Fig. 6. Oil recovery factor and pressure drop as a function of the injected PVs of SW, SMSW2, and CO2 for RC8d.

3.3.3. Scenario#5: SW + SMSW3 + CO2 Like the previous two experiments, this experiment was conducted by depleting Ca2+ from SW. The oil recovery during the first 8 PVs of the injected SW was 19.35% of the OOIP. The improved oil recovery was 12.9% of the OOIP after injecting 8 PVs of SMSW3. The pressure drop tended to stabilize at the end of SW flooding, but injecting SMSW3 increased the pressure due to fines migration, which was also seen by the naked eye. The pressure drop also decreased during CO2 as explained previously. The improved oil recovery during 10 PVs of the injected CO2 was the highest, which was 64.52% of the OOIP. It is evident that removing Ca2+ from SW prompted considerable improvement in oil recovery. The results are shown in Fig. 7.


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ΔP 400

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Injected Pore Volume Fig. 7. Oil recovery factor and pressure drop as a function of the injected PVs of SW, SMSW3, and CO2 for RC8e.

The experimental study conducted by Reinholdtsen et al. (2011) on sandstone reservoir core by flooding SW provided 4% OOIP32. The concentration of Ca2+ was then diluted three times in the SW, and the oil recovery increased while diluting Mg2+ six times, but no additional oil recovery was observed. The solubility of CO2 in the injected fluids increases as the salinity of the injected fluids decreases. These solubility results were observed by Li and Nghiem (1986), Pollack et al. (1988), Enick and Klara (1990), and Duan and Sun (2003) 33-36. As mentioned previously, we kept the salinity of all brines at 51,400 ppm while the brine was softened by depleting SO4, Mg2+, and Ca2+. We believe that the CO2 solubility in brine decreased as the concentration of the SO4, Mg2+, and Ca2+ decreased (the largest in Ca2+), resulting in a higher solubility in crude oil, and in turn, increasing oil recovery. Thus, we saw higher oil recovery when SO4, Mg2+, and Ca2+ were depleted in SW. That explains the incremental oil recovery with CO2 injection as the concentration of the Ca2+ decreased. Aksulu et al. (2012) reported that increasing Ca2+ concentration in the injected water moved the reaction Clay – Ca2+ + H2O ↔ clay – H+ + Ca2+ + OH- + heat to the left37. The reaction movement to the left causes a pH reduction, and no water wetness condition can be achieved since the negatively charged carboxylic acid in the crude oil will creates a -COOCa+ group at the negative clay sites. Additionally, we studied the influence of divalent cations Ca2+ and Mg2+ in the injected water and FW, and we concluded that removing Ca2+ and Mg2+ has a positive effect on the improved oil recovery, Ca2+ showed the tremendous impact2, 37. In Al-Saedi et al. (2019a), we reported that Mg2+ has a ~30% smaller radius than Ca2+ and hence is more strongly hydrated39. Thus, the effective hydrated radius of Ca+2 is lower than that of Mg+2. This may allow Ca2+ carboxylate groups to be more tightly bound to mineral surfaces than Mg2+ carboxylate groups. For that, we conducted a CO2 solubility test (CO2 solubility in brine section) to understand the solubility of CO2 and the various incremental oil recovery.


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3.4. Scenario#6: SW + LSW + CO2 This experiment differs from the previous experiments by replacing SMSW brines by LS water to investigate the effect of LS water on CO2 flooding and to investigate whether depleting partial ions in SW is better than diluting all the water. The same procedure and injected pore volumes were applied as in the previous experiments. RC8f was flooded with 8 PVs of SW, and the resulted oil recovery was 19.44% of the OOIP. Upon switching to LS water, the oil recovery improved significantly. The oil recovery due to LS water was 27.78% of the OOIP, which was higher than all oil recoveries obtained by all the brines used in this study. This high oil recovery was due to the LS water effect on sandstone, which ascribed to many mechanisms discussed in the literature. Some of these mechanisms are listed in the introduction. However, the most accepted explanation is LS water triggers the wettability of the rock towards being more waterwet. Wettability of the rock for all the cores used in this study has been measured and explained in the wettability section. Miscible CO2 flooding was performed after LS water flooding by injecting 10 PVs of CO2. The oil recovery by injecting CO2 was 44.44% of the OOIP. The oil recovery due to CO2 flooding was high but much smaller than that in scenario#5 where SMSW3 was flooded before CO2. The oil recovery of 44.44% was similar to that in scenario#3, where SMSW1 was injected before CO2 (44.44% vs. 43.75%). Thus, the 94.45% recovery in scenario#6 was because of LS water effect during LS water, not during CO2, which is opposite from scenario#5, where SMSW3 triggered CO2 to dissolve in crude oil. The results of this experiment are shown in Fig. 8. The differential pressure during SW flooding is similar to the previous cores, but during LS water flooding a rapid increase was noted in the differential pressure curve due to fines movement. 1600

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3.5. Observation from core-flooding experiments The obtained oil recovery from the six core-flooding experiments is shown in Figs. 3-8. In the first experiment (CO2 only), the gravity override, early breakthrough, and viscous channeling cause poor sweep efficiency of the injected CO2, which improves the oil recovery but not efficiently. The oil recovery from 14 ACS Paragon Plus Environment

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injecting CO2 only was 78.57% of the OOIP, while injecting SW prior to CO2 yielded higher oil recovery (86.7%). After that, SW compositions were modified in order to attain more oil recovery, not depending on improving sweep efficiency of the CO2, but instead achieving more characteristics and advantages that could increase oil recovery such as wettability alteration, CO2 solubility in crude oil other than in the injected brines and improve sweep efficiency. The first modification was by depleting Na2SO4 in SW, which significantly enhanced oil recovery to 90.63% OOIP. The second modification was by removing MgCl2 from SW, which also improved oil recovery (88.7% OOIP), but slightly lower than when Na2SO4 was depleted. The third SW modification was removing CaCl2, and the highest oil recovery was obtained in this experiment, which was 96.8% of the OOIP. Finally, the oil recovery due to LS water with CO2 was also high (lower in 2.35%), but the most substantial oil recovery was while injecting LS water, not during CO2 flooding. The oil recovery was high due to miscible CO2 injection and the new method of SMSWs and miscible CO2. However, this high oil recovery is more achievable in the laboratory due to the small crosssection of the cores. Heterogeneity and fractures and other reservoirs characteristics limiting obtain a higher oil recovery like that in the laboratory.

3.6. CO2 solubility in brine CO2 solubility in brine was measured using the pressure decay method. It was reported by Mosavat and Torabi (2013) that CO2 solubility increases as brine salinity decreases41. The SW and SMSW brines' salinity are equal (51,400 ppm). Conducting a CO2 solubility test on four brines equal in salinity could explain why higher oil recoveries were obtained by injecting brines equal in salinity. Fig. 9 shows the CO2 solubility results. As can be seen from Fig. 9, the solubility of CO2 in SMW3 is less than in SW, SMSW1, and SMSW2, which redirects part of CO2 to dissolve in crude oil, and additional oil recovery was obtained. As the concentration of Ca2+ was depleted in SW, the CO2 solubility in that brine decreases too, which explains the higher oil recovery by injecting SMSW3 before CO2. In addition, removing/diluting Ca2+ from the injected water triggers the core wettability towards being more water-wet, which also increases oil recovery. The solubility of CO2 in LS water agreed with Mosavat and Torabi’s study, and that high solubility of CO2 in LS water explained why the oil recovery by SMSW3 and CO2 is higher than by LS water and CO2 even though the salinity of LS water is 50 times lower than SMSW3. The high oil recovery recovered by LS water and CO2 flooding, on the other hand, is ascribed to the low salinity of LS water, which altered the sandstone salinity towards water-wet as will be explained in the wettability measurements section. MOLALITY, MOLE OF CO2 / KG OF BRINE

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0.844 0.71 0.64

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3.7. Contact Angle Measurements Table 4 and Fig. 10 show the contact angle measurement’s results for RC8b, RC8c, RC8d, RC8e, and RC8f when the surrounding fluids are SW, SMSW1, SMSW2, SMSW3, and LS water, respectively. For all cores, a wettability alteration from oil-wet to water-wet was observed with depletion in the concentration of SO42-, Mg2+, and Ca2+ in the smart seawaters while the salinity was constant at 51,400 ppm (same as seawater salinity). The contact angle results for the same cores and SMSWs decreased in the carbonated SMSWs. The contact angles in the presence of LS water were greater than the contact angles for smart waters even though the salinity of LS water was ten times less than SMSWs, meaning that depleting the divalent cations/anion (SO42-, Mg2+, and Ca2+) is more effective than reducing the salinity of the water. The highest contact angle was observed in the presence of the SW, which was 142.66 and 131 at SW and carbonated SW, respectively. This observation is consistent with the observations of Teklu et al. (2016)21. The measured contact angles among SMSWs were approximately in the same range. While contact angle when SW presented is high due to the high salinity of the SW. There is a large difference between the measured contact angle by SW and by SMSWs which is due to SMSWs induce wettability alteration towards being more water-wet. Depleting divalent cations/anions trigger wettability alteration even though the salinities were the same, and the highest effect on wettability was depleting Ca2+. Contact angles for SMSW brines were lower than contact angles when LS water was used. The higher oil recovery during LS water might be due to the effect of other mechanisms of LS water such as a reduction in interfacial tension and increased pH7 in addition to the wettability alteration, as can be seen from contact angle measurements. However, the pH measurements indicate that the LS water effluent pH was higher than that in all SMSWs used in this study (Fig. 11). The upward shift in effluent pH difference is traditionally ascribed to exchange of H+ for Ca2+ on clay surfaces. In addition, we reported in our previous study that a cation exchange on quartz surface and an organic material desorption from quartz surface trigger more oil to be detached from quartz surface40. Austad et al. (2010) ascribed the improved oil recovery to organic material desorption from the clay surface10.

Table 4 Contact angle results. CORE NO. SW SMSW1 SMSW2 SMSW3 LSW

CONTACT ANGLE Non-Carbonated 142.66 55 62 48 89

Carbonated 131 50.7 59.4 39.2 85


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3.8. Spontaneous imbibition The Amott cells were set in the room temperature, and no oil drainage was observed during the first week. Due to its high viscosity, the oil inside the cores needs to be heated to make it easier to move out the cores. The Amott cells were transferred inside the oven, which was set on the same core-flooding experiments temperature (50°C). The oil was witnessed moving out of the cores inside the imbibed fluids except for the core immersed in SW. The oil drainage was prolonged, and only a small amount of oil was produced due to the low work applied in the cores to displace the oil in place compared to the achieved work by core 17 ACS Paragon Plus Environment

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flooding. We left the cells inside the oven for 100 days. The oil stopped to drainage out of the cores at different times, and the latest was SW. As can be seen from Figure 12, only 3.33% OOIP was recovered by SW. The crude oil is viscous, so it is not easy to displace viscous oil by spontaneous imbibition. The oil recovery due to SMSW1 and SMSW2 was similar, which was ~20% of the OOIP. The recovered oil due to SMSW3 was 23.8% OOIP, while it was 25% OOIP for LS water. It is evident that depleting Ca2+ in SW has the same effect as diluting SW 10 times. Fig. 12 shows imbibition results. 100 LSW SW

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3.9. Impilcations of the results LS water is an immense EOR technology to increase oil recovery by altering the sandstone wettability towards more water-wet and in turn increase oil recovery. Injecting LS water prior to CO2 is an excellent candidate to alter rock wettability and to improve the sweep efficiency of the CO2. However, SW is plenty available, and using SW in EOR is much easier than diluting it to make LS water. A simple modification to SW is also a good option when injecting before CO2. This modification includes removing Ca2+ only, which provides the wettability alteration that LS water provides and lowers the CO2 solubility in the injected brine, which redirects CO2 to dissolve in the crude oil more than if LS water was pumped beside the sweep efficiency improvement. It is correct the fact that there are brines that can induce wettability alteration and have high salinities42. The solubility of CO2 in lower salinity brine is high, which consumes a significant portion of the injected CO2 inside the injected water other than the crude oil. This proposed method provides more oil recovery from heavy oil reservoirs at 96.8% of the OOIP, which is 2.35% (in total) more than when LS water is injected. This percentage difference is in general, but the differences in oil recovery due to CO2 flooding was 20.07% (65.52 vs. 44.44%). Combining LS water with CO2 is also an excellent method to extract more heavy oil, but the most recoverable oil was during LS water, not during CO2 flooding. The oil recovery results due to CO2 when LS water was injected was similar to that in SMSW1. Thus, the high oil recovery from scenario#6 was during LS water flooding by itself, not during CO2 flooding, while the 18 ACS Paragon Plus Environment

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substantial oil recovery in scenario#5 was due to CO2 solubility in crude oil because of the lower solubility of CO2 in SMSW3. The optimum case was when Ca2+ depleted and injecting that smart water prior to miscible CO2. There is still potential for further perfections. It is recommended to SW-SMSW3-CO2 scenario and inject them in many cycles (i.e., WAG).

4. Conclusion Core-flooding experiments, spontaneous imbibition tests, contact angle measurements, and CO2 solubility tests have been conducted in this study to evaluate the proposed method of injecting smart seawater prior to CO2 to improve oil recovery. Water was used with CO2 to improve its sweep efficiency, and a higher oil recovery could be obtained. Recently, regular water was exchanged with LS water for its ability to alter wettability and to improve sweep efficiency. However, LS water is thought to be the best alternative for regular water in the WAG process, but based on this study, smartening seawater could provide higher oil recovery. The following conclusions were drawn:  CO2 was found to be less soluble in smart seawater brines, and the lowest solubility was when Ca2+ was depleted in SW. The less solubility of CO2 in the injected smart water bypassed a portion of the injected CO2 to dissolve in crude oil and resulted in increased oil recovery. In addition, removing Ca2+ from the injected water triggered the core wettability towards being more waterwet, which also increased oil recovery.  The total oil recovery obtained by injecting LS water and CO2 was also high, but the most recovered oil was during LS water (LS water produced 27.78% and CO2 produced 44.44%) (Compared with SMSW3), while the oil recovery during injecting SW depleted in Ca2+ and CO2 was mostly during injecting CO2 (SMSW3 produced 12.9% and CO2 produced 64.52%).  The reservoir sandstone cores showed a wettability alteration towards being more water-wet in both LS water and smart seawater brines. Decreasing injecting water salinity or manipulating its compositions provided approximately the same wetting conditions.  Diluting other ions such as Mg2+ or SO42- resulted in a high oil recovery of 33.87% and 43.75% OOIP, respectively, when CO2 was injected after smart seawater. The oil recovery provided from CO2 flooding after injecting SW depleted in SO42- was similar to that when LS water was injected before CO2.

Acknowledgment We would like to express our appreciation the Higher Committee for Education Development in Iraq and the Iraqi Ministry of Oil/ Missan Oil Company for funding this study. Additional thanks to Colt Energy, Inc., especially John Amerman, for providing crude oil and reservoir cores for this study. Many thanks to Emily Seals for her help proofreading this study.

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