A pH-Resolved Wettability Alteration: Implications for CO2-Assisted

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A pH-resolved Wettability Alteration: Implications for CO2-assisted EOR in Carbonate Reservoirs Quan Xie, Yongqiang Chen, Ahmad Sari, Wan-Fen Pu, Ali Saeedi, and Xinwei Liao Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b03071 • Publication Date (Web): 14 Nov 2017 Downloaded from http://pubs.acs.org on November 16, 2017

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A pH-resolved Wettability Alteration: Implications for CO2-assisted EOR in Carbonate Reservoirs Quan Xie †*, Yongqiang Chen †, Ahmad Sari †, Wanfen Pu ‡, Ali Saeedi †, Xinwei Liao § †

Department of Petroleum Engineering, Curtin University, GPO Box U1987, Australia, Perth,

W.A. 6845 ‡

State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum

University, Chengdu, Sichuan 610500, China §

College of Petroleum Engineering, China University of Petroleum (Beijing), 102249 Beijing, China

ABSTRACT Wettability of oil/brine/rock system is a critical petro-physical parameter, which governs subsurface multiphase flow behavior, thus hydrocarbon recovery. While the mechanisms of CO 2assisted enhanced oil recovery (EOR) techniques have been extensively investigated in carbonate reservoirs, few have done to identify the controlling factor of CO 2-induced wettability alteration, and fewer have look beyond the implications for CO2-assisted EOR. We thus hypothesize that CO2-assisted EOR techniques cause a more hydrophilic system due to H+ adsorption on the interface of oil/brine and brine/carbonate as a result of CO2 dissolution. To test this hypothesis, we measured contact angles of two oils with different acid and base number in the presence of 1M

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Na2SO4 at pH either 3 or 8. Moreover, we performed a geochemical study to identify the controlling factor of wettability alteration. Contact angle results support the hypothesis, showing that the oil/brine/rock system shifts towards more water-wet because of less bonds between oil/brine and brine/carbonate due to H+ adsorption on the interface of oil/brine and brine/carbonate. Our results also suggest that CO2-assisted EOR techniques likely shift relative permeability curves towards a lower residual oil saturation due to wettability alteration. We argue that geochemical reactions may need to be incorporated into reservoir numerical model, thus better managing and predicting the performance of CO2-assisted EOR.

Keywords: Carbonate reservoirs, CO2-assisted EOR, pH, Wettability, Geochemical reactions

1. INTRODUCTION Low emission energy (e.g., oil and natural gas) remains as important resources in this century.1 As global energy demand continues to increase, the petroleum industry is constantly striving to develop economically viable techniques to maximize oil recovery in carbonate reservoirs.2 This is largely because carbonates rock host most of the world’s oil reserves (> 60 %),3 which are composed primarily of the minerals calcite and dolomite together with impurities, e.g., quartz, anhydrite, clay minerals, organic matter, and apatite.4 However, average recovery typically is lower than 40%.5 Cost-effective and environmentally friendly techniques to enhance oil recovery from carbonates are therefore of broad scientific interest.6 CO2-assisted EOR techniques (e.g., miscible

7

injection,11,

and immiscible continuous injection,8, 12

9

carbonate water flooding,10 huff and puff

and water-alternating-CO213-15 have gained interests in scientific research and

industry. This is largely because CO2-assisted EOR techniques can enhance oil recovery in a cost-


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effective and environmentally friendly way (e.g., decreasing the use of toxic chemicals and cutting back on the greenhouse gas emission released.16). For conventional reservoirs, CO2-assisted techniques achieve a few driving processes (e.g., solution gas drive, immiscible drive, first contact miscible drive, vaporizing-gas drive, condensinggas drive, and vaporizing/condensing gas drive or multiple-contact miscible drive process). Recent experimental study also show that CO2 huff-n-puff has a huge potential to achieve 14 % additional oil recovery from unconventional liquid rich reservoirs.17 These driving process can (a) promote oil-swelling, (b) reduce oil viscosity, (c) mitigate gravity segregation as a result of reducing density difference between oil and water, (d) lower IFT between hydrocarbon-enriched CO2 and CO2-saturated oil. (e) Shift oil/brine/rock system wettability towards water-wet. While the mechanisms of (a) to (d) have been extensively investigated, the controlling factor(s) of mechanism (e), wettability alteration has not been clearly defined due to the complexity of the interaction of oil/brine/rock system. This lack brings uncertainties to better manage and predict the performance of CO2-assisted EOR techniques. In this work, we thus hypothesize that excess H+ generated by dissolved CO2 into connate water (formation brines) would lift off the attached polarized ends in crude oils from pore surfaces due to competitive ion adsorption. To test this hypothesis, we measured contact angles of two oils (Oil A with acid number of 4.0 and base number of 1.3 mg KOH/g; and Oil B with acid number of 1.7 and base number of 1.2 mg KOH/g) in the presence of 1M Na2SO4 at pH either 3 or 8. Moreover, to gain a deeper understanding of the interaction of oil/brine/rock system, we performed a geochemical study, examined the effect of pH on the number of surface species at oil/brine and brine/carbonate interfaces, thus wettability.


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2. EXPERIMENTAL PROCEDURES 2.1 Materials 2.1.1 Oil Given that oil composition likely affects the interaction of oil/brine/rock system, thus wettability,18 two oils were used to test our hypothesis. For example, oil A has a high acid number of 4.0 mg KOH/g, and oil B has a low acid number of 1.7 mg KOH/g compared to oil A. Also, oil A and B have similar base number, 1.3 and 1.2 mg KOH/g, respectively. Oil properties (e.g., Asphaltene, density) at temperature of 20 oC for oil A and B were listed in Table 1. Table 1: Experimental oil properties Acid number

Base number

Asphaltene

Density

(mg KOH/g)

(mg KOH/g)

(mg KOH/g)

(g/cm3) at 20oC

Oil A

4.0

1.3

0.54

0.85

Oil B

1.7

1.2

0.10

0.89

Oil sample

2.1.2 Brine Given that this study aims to test our hypothesis that CO 2-assisted EOR techniques will cause a more hydrophilic system due to H+ adsorption on the interface of oil/brine and brine/carbonate, we experimentally adjusted pH of experimental brines, which is approximately equivalent to the pH of CO2-assisted EOR schemes, rather mixing CO2 with brines. We first calculated the solubility of CO2 in the brine under temperature of 60 oC and pressure of 190 bar, using a published and widely accepted model.19 We then derived the magnitude of pH under the reservoir conditions, using a model presented in the literature.19 Based on the brine salinity, temperature and pressure, the pH under the reservoir conditions was calculated to range from 3.0-3.5 in line with the literature 20

as brines are saturated with CO2. Therefore, to particularly test pH effect on system wettability,


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we tested contact angle at two different pH (pH=3 and 8) in the presence of 1 mol Na 2SO4. Note: in this study, pH=3 represents the in-situ reservoir pH condition during CO2-assisted EOR implementation, and pH=8 represents a normal reservoir pH condition. 2.1.3 Carbonate rocks Rock mineralogy is essential to wettability alteration in carbonate reservoirs. X-ray diffraction (XRD) of rock samples used in the contact angle measurements showed 98.1 % calcite, 0.7% quartz, and 1.2% Ankerite, but no detectable anhydrite (CaSO4).To ensure the integrity of contact angle measurements, the rock substrates were cleaned with methanol to remove any trace of inorganic contaminants, and rinsed with equilibrated deionized water. Then, clean and dry substrates were exposed to air plasma for 10 min to remove organic surface contamination.21

2.2 Experimental Setup 2.2.1 Contact angle set-up In this study, contact angles for oil/brine/rock system were performed using Vinci IFT-700 (Figure 1). The experimental temperatures were 25, 60 and 100 oC which cover the temperature range for typical oil reservoirs. Pressure was kept constant at 100 bar for all experiments. Contact angle tests were performed using the sessile droplet method. Substrates were placed inside the HTHP cell and vacuumed before filling with the relevant brine. Subsequently, pressure and temperature were applied. Once the state of temperature and pressure equilibrium was achieved, a droplet of crude oil (0.04 – 0.06 ml) was released through a small needle (D = 0.6 mm) onto the substrate surface. A high definition video camera continuously recorded the experiment where contact angles were measured over the period of 48 hours using the built-in software. Once the state of equilibrium was achieved and no more change in contact angle was detected, result was


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reported as the final contact angle for the system. The standard derivation of contact angle measurements was ±2o. It is worth noting that while factors such as the substrate roughness, contact angle hysteriss, and preparation procedure all may affect the the macroscopoic contact angle,22 the philosophy of the contact angle tests in this study was to highlight the actual trend of the contact angle with pH, rather than the exact initial value of the contact angle. Also note that in this study, we did not age the substrates before testing contact angles. This is because aging process tends to make the rock more oil-wet by re-establishing adsorption equilibrium between the rock surface and the crude oil.23 This study aims to investigate the effect of pH on the wettability of carbonate rocks. Using a strongly oil-wet surface in our experiments would mean that possible change in the wetting preference from water-wet to oil-wet due to change in pH could not be observed.

Valve

High definition camera

Hand pump (brine)

Light source

HI-HP IFT cell

Valve

Data recording system

Hand pump (crude oil)

Figure 1: Schemat ic of contact angle and interfacial tension apparatus.


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2.2.2 Surface complexation modelling We used the surface complexation model developed by Brady et al. 24, 25 to calculate the number of charged species that are thought to cause local adhesion of the oil/brine interface to the brine/calcite interface, hence wetting. The bond product sum counts the number of electrostatic connections between the two. Surface complexation modelling (and DLVO theory) presumes an electric double layer at each interface and the existence of charged surface species whose concentrations depend upon the chemical makeup of the water and the oil and mineral surface.26 In the surface complexation model, the calcite surface area was assumed as 10 m2/g with site density of 10 μmol/m2. 24 The chemical reactions on the surface of calcite can be described by the following reactions (Table 2). We used 25 oC Log K for all of the chemical reactions in Table 2 because water chemistry dominates the surface complexation of the oil/brine/rock system and temperature plays a secondary effect.26 The surface species concentrations were calculated using PHREEQC version 3.3.9 (Parkhurst and Appelo 2013) and a diffuse layer surface model. Table 2: Surface complexation model input parameters 24, 27-29 Interface

Reaction

Reaction

oil/brine

-NH+ = -N + H+ -COOH = -COO- + H+ -COOH + Ca2+ = -COOCa+ + H+

Log K25oC -6.0 -5.0 -3.8

calcite/brine

>CaOH + H+ = >CaOH2+ >CaOH + HCO3- = >CaCO3 - + H2O >CaOH2+ + SO42- = >CaSO4- + H2O >CO3H = >CO3- + H+ >CO3H + Ca2+ = >CO3Ca+ + H+ >CO3H + Mg2+ = >CO3Mg+ + H+

11.85 5.8 2.1 -5.1 -2.6 -2.6

4 5 6 7 8 9

1 2 3

Where “>” denotes a site on the carbonate surface while “-” denotes a site on the oil surface. Note: due to the absence of CaCl2 and MgCl2 in the experimental brines, Reaction 3, 8 and 9 were not included in the geochemical reaction computation.


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3. RESULTS AND DISCUSSIONS 3.1 Effect of pH on the contact angle pH strongly affected contact angle for both oils. In general, pH=3 rendered a smaller contact angle compare to pH=8, implying that decreasing pH shifts oil/brine/carbonate system towards water-wet, or strongly water-wet. For example, at temperature of 60 oC, pH=3 exhibited contact angle of 25o, and pH=8 gave contact angle of 70o for crude oil A. Similar to crude oil B at temperature of 60 oC, pH=3 exhibited contact angle of 52o, and pH=8 gave contact angle of 175o, meaning a strongly oil-wet system. Our contact angle results support our hypothesis that decreasing pH to 3 shifts the oil/brine/carbonate system towards more water-wet. This is largely because that at pH=3, excess H+ lift off the attached polarized ends in crude oils from pore surfaces due to geochemical reaction between the two interfaces, oil/brine and brine/carbonate, which were discussed using surface complexation modelling in the section below. Our results are also in line with Teklu et al.30 who show that the contact angle of oil on the carbonate substrate decreased from 133.6 to 36.1o as they progressed from measurement condition A to B. Note that A means a base case contact angle using seawater; B means a mixture seawater and 200 ml CO 2 at 2,500 psi. Their results imply that low pH due to the CO2 dissolved in the seawater shifted oil/brine/carbonate system towards a strongly water-wet system.


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Figure 2: Contact angle vs. temperatures at pH=3 and 8, respectively (Crude oil A).

Figure 3: Contact angle vs. temperatures at pH=3 and 8, respectively (Crude oil B).

3.2 Effect of oil composition on contact angle Oil composition also strongly affected the contact angle. To be more specific, the crude oil A with a high acid number (4.0 mg KOH/g) gave a lower contact angle compared to crude oil B with the low acid number (1.7 mg KOH/g). For example, at pH=3 and pH=8 at temperature of 25 oC, crude oil A exhibited the contact angle of 25 and 29 o, respectively, yet crude oil B gave the contact


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angle of 48 and 175o. This is because Na2SO4 may trigger calcite dissolution at pH=3 and 8, thus Ca2+, which in return forms –COOCa+ at interface of oil/brine. Note: the oil with high acid number means high number of surface species of –COOCa+ at oil/brine, suggesting a repulsive force between oil/brine and brine/carbonate because surface charges at brine/carbonate consists of >CaOH2+ and >CO3Ca+. Contact angle of high acid number oil A on a substrate was sensitive to temperature as temperature was lower than 60 oC at pH =8. For example, the contact angle of oil A (AN=4.0 mg KOH/g) increased dramatically (i.e., from 29 to 70o) as temperature increased from 20 to 60 oC. Yet, this change was not observed with low acid number oil B. This is probably because the Reaction 2 shifts towards right-hand side with increasing temperature, increasing [- COO][>CaOH2+], thus less water-wet although a more quantitative work remains to be made. Note: an oil with a greater acid number means more –COO-. However, contact did not change with further increasing temperature to 100 oC for both oils at pH=8. At pH=3, contact angle of high acid oil A did not change with increasing temperature, whereas contact angle of low acid number oil B changed slightly with increasing temperature. This implies that at low pH, pH governs the oil/brine and brine/carbonate surface chemistry, and oil composition, water chemistry may play a secondary effect. Therefore, we conclude that CO2-assisted EOR techniques appears to shift oil/brine/carbonate system towards more water-wet. 3.3 Effect of temperature on contact angle Temperature had a little effect on contact angle of low acid number oil B (Figure 3). At pH=8, contact angle did not change with increasing temperature although contact angle increased slightly with increasing temperature at pH=3. For example, at pH=8, Na 2SO4 gave contact angle of 175 o


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as temperature increasing from 20 to 100 oC. At pH=3, contact angle increased from 48 to 70o in the presence of Na2SO4. For crude oil A at pH=8, contact angle increased sharply (29 to 70 o) as temperature increased from 20 to 60 oC (Figure 2), whereas contact angle kept constantly with further increasing temperature. At pH=3, similar to oil B, contact angle did not change with temperature. Together, the variation of contact with temperature (CaOH2+], thus less water-wet. However, this assumption needs to be quantitatively validated by coupling electrostatic and non-electrostatic physisorption together with competitive ion chemisorption (ion exchange and surface complexation) 20. The variation of contact angles in the presence of different pH was discussed in the section below. 3.4 Surface complexation modelling To gain a deeper understanding of the pH effect on the interaction of oil/brine/rock system, thereby wettability, we conducted a surface complexation modelling, quantitatively describing how pH affects the bond product sum which is an indicator of wettability.24 Note: bond product sum means a measure of the amount of oil-mineral electrostatic attraction, which is given by the summed products of the oppositely charged surface species on the interface of oil/brine and brine/mineral.31 pH strongly affected the number of surface species at oil/brine interfaces termed as site density (Figure 4) for both oil A and B. To be more specific, for a certain oil, -COO- increased with increasing pH due to Reaction 2 shifting towards right-hand side. Rather, -NH+ decreased with


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increasing pH due to the Reaction 1 driving towards right-hand side. For example, for crude oil A, -COO- increased from 20 to 32 µmol/m2 as pH increased from 2 to 9. –NH+ decreased from 22.3 to 21.9 µmol/m2 with increasing pH. Similarly, crude oil B follows the same trend for –COO- and –NH+, whereas site density for both were lower than crude oil A due to the low acid number. The variation of site density versus pH is in line with previous studies

24, 26, 32

because the number of

surface species are governed by Reaction 1 to 3 in Table 1.

Figure 4: Site density of surface species at oil/brine (-COO- and –NH+) vs. pH for oil A and B. pH also strongly impacted the site density of surface species (e.g., >CO 3-, >CaSO4-, >CaOH2+) at brine/carbonate interfaces (Figure 5). To be more specific, >CaOH 2+ kept almost constantly till pH reached at 4, then increased sharply till pH reached at 7, subsequently kept almost constantly again. This is because as pHCaOH2+ at low pH, whereas the compensation decreased as pH increased to 7, and ultimately reached in equilibrium. Similarly, >CO3- followed the same trend as >CaOH2+. For example, >CO3- increased dramatically from almost 0 to 4.5 µmol/m2 as increasing from pH 4 to 7 due to the Reaction 7 shifting towards right-hand side in line with Brady et al.24 Yet, >CaSO4- followed the opposite of >CaOH2+ and >CO3 -, showing that the site density


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decreased from 2.65 to 1.04 µmol/m2 as pH increasing from 4 to 7. This is due to the fact that Reaction 4 and 6 shifted towards left-hand side with increasing pH. Our results are also in line with Mahani et al.33 who show that >CaSO4- in the presence of seawater decreases from 8 to 3 µmol/m2 with increasing pH. However, they observed the site density decrease sharply as pH increasing to 7.5. This may largely because in the presence of sea water, at pH range 6.5-8.5, the surface charge is governed by >CO3Mg+, >CO3Ca+ and >CaSO4- because their concentration is approximately 1000 times larger other species.33

Figure 5: Site density of surface species at brine/carbonate vs. pH.

Bond product sum (BPS=[-NH+][>CO3-]+[-NH+][>CaSO4-]+[- COO-][>CaOH2+]) increased with increasing pH (Figure 6) for a given oil, implying that the oil/brine/carbonate system likely becomes more oil-wet. For example, for Oil A, BPS increased from 98 to 232 (µmol/m2)2 with increasing pH from 2 to 9. For oil B, BPS increased from 82 to 172 (µmol/m2)2 with increasing pH. Together, the variation of BPS versus pH for both oils suggest that the oil/brine carbonate system in this study become more oil-wet as increasing pH. This is in line with contact angle test for each of oil/brine/carbonate system, showing that contact angle increased with increasing pH.


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However, the bond product sum of Oil A and B raises the question: why did Oil A give a greater BPS compared to Oil B at a given pH, but exhibits a lower contact angle at pH=3 and 8. For example, contact angle results show that Oil A exhibited a contact angle of 25 and 70 o at temperature of 60 oC, whereas Oil B gave a contact angle of 48 and 175 at pH of 3 and 8, respectively. Two potential explanations for the discrepancy are that: 1. During the contact angle test, Ca2+ could be generated because of dissolution, which in return formed –COOCa+. Note that crude oil A with high acid number may give more –COOCa+, which means less bond of [- COO-][>CaOH2+], thus less oil-wet system compared to oil B. 2. Bond product sum, BPS, is an explicit parameter to indicate an oil/brine/rock system wettability, which does not consider non-electrostatic physisorption together with competitive ion chemisorption. Note that the absolute values of the bond product sum of the system is not important, but rather the change in bond product sum (Figure 6), which provides a visualization of the effects of pH on the bond product sum, thus wettability alteration. Figure 6 shows that bond product sum decreased with decreasing pH, implying a more water-wet systm. Also note that in our experiments, we did not mix CO2 with brine to create an in-situe pH condition. Rather, we exmianed the contact angle at pH=3 to mimic the low pH condition as a result of CO2 dissolution. With CO2 dissolution, HCO3- would be generated, thus the increase of >CaCO3 - and [>CaCO3 -][-NH+]. However, [>CaCO3 -][-NH+] would decrease with decreasing pH because both >CaCO3 decreases

24, 26

33

and -NH+

with decreasing pH. Therefore, we conclude that CO2-assisted EOR techniques

likely shifts wettability towards more water-wet due to excess H+ adsorption on the surface of oil/brine and brine/rock.


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Figure 6: Bond product sum of oil/brine/carbonate vs. pH for oil A and B.

4. IMPLICATIONS CO2-assisted EOR techniques (e.g., miscible and immiscible continuous injection, carbonated water flooding, huff and puff injection, and water-alternating-CO2) appear to be a cost-effective and environmentally friendly means to unlock the oil resources from both conventional sandstone, unconventional resources and carbonate reservoirs. While wettability alteration towards water-wet has been confirmed experimentally to be as one of the main mechanisms to achieve an incremental oil recovery,13, 30 what factor controlling the wettability shift is not clearly defined. In this work, we combined contact angle tests and a geochemical study to demonstrate that CO2-assisted EOR techniques probably shift wettability towards more water-wet due to H+ adsorption at the interface of oil/brine and brine/carbonate, which can be described by geochemical reactions listed in Table 1. Our contact angle tests and the geochemical study provide insights on the CO2-assisted EOR techniques, thus limiting the uncertainty of field application in carbonate reservoirs. Therefore, we


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argue that geochemical reactions may need to be incorporated into numerical reservoir simulation to better manage and predict the reservoir performance. We believe that CO2 can facilitate low salinity water flooding. This is not only because of increasing sweep efficiency and decreasing interfacial tension of oil/brine. Moreover, low salinity water yields a higher solubility of CO2 (Teklu et al.,13 Figure 1), which in return provides excess H+ to decrease the bond product sum between oil/brine and brine/rock interfaces, thereby a hydrophilic oil/brine/rock system. This is also supported by Teklu et al.’s

30

contact angle tests,

which show that contact angle decreased dramatically from 133.6 in the presence of seawater to 36.1o in the presence of mixture of seawater and 300 ml CO2. We also believe that CO2 huff-n-puff in unconventional liquid rich shale reservoirs can shift system wettability towards more water-wet. This is also related to fact that excess H+ generated by CO2 dissolution can decrease the bond product sum between oil/brine and brine/rock interfaces, thereby a hydrophilic oil/brine/rock system. Further, CO2-assisted EOR techniques may also induce fines migration for reservoirs with high content of kaolinite. We believe that some kaolinite particles probably lifted off and detached from neighbouring kaolinite particles rather than quartz grains at low pH.20 This is also in line with Ramanthan et al.14 who observed kaolinite migration during low salinity water-alternating-CO2 flooding. This can be interpreted by geochemical reactions (Brady et al.,32 Table 1), which show that at low pH, kaolinite surface will be governed by >AlOH2+, generating repulsive force between kaolinite particles. Rather, quartz surface likely has much less >SiOCa + at low pH to trigger repulsion. However, for reservoirs with basal charge controlled clays (e.g., smectite, illite, and chlorite), fines migration may less likely take place for CO2-assisted EOR techniques.


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Note: while we believe that CO2-assisted EOR techniques can shift system wettability towards more water-wet, to deeply understand and predict the wettability alteration, we hypothesize that the interaction of Crude Oil/Brine/Rock is controlled by both electrostatic and non-electrostatic physisorption together with competitive ion chemisorption (ion exchange and surface complexation). The contribution of each of these mechanisms can be incorporated into the total surface energy which determines adhesion of oil to the rock surface, see schematic diagram below, Figure 7.

Figure 7: Illustrative cartoon of physics (none/electrostatic physisorption, competitive ion chemisorption) of CO2-assisted EOR techniques.

5. CONCLUSIONS Understanding the wettability of oil/brine/carbonate rock has long been a goal of reservoir engineers.34, 35 While the mechanisms of CO2-assisted enhanced oil recovery (EOR) techniques have been extensively investigated, few have done to identify the controlling factor of CO2induced wettability alteration, and fewer have look beyond the implications for CO 2-assisted EOR. In this work, we combined contact angle tests and geochemical studies to determine that CO 2assisted EOR techniques will cause a more hydrophilic system due to H+ adsorption on the interface of oil/brine and brine/carbonate as a result of CO 2 dissolution, which is also supported by previous studies (Teklu et al.’s 13, 30), showing that contact angles decreased dramatically from


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133.6 in the presence of seawater to 36.1o in the presence of mixture of seawater and 300 ml CO2. Together, these imply that CO2-assisted EOR techniques likely shifts petrophysical parameters, e.g., relative permeability and capillary pressure curves towards a lower residual oil saturation, thus accelerating oil production rate and improving oil recovery.36 We also argue that geochemical reactions may need to be incorporated into reservoir numerical model, thus better managing and predicting the performance of CO2-assisted EOR. However, to deeply understand and predict the wettability alteration, we believe that both electrostatic and non-electrostatic physisorption together with competitive ion chemisorption (ion exchange and surface complexation) need to be coupled for future work.

AUTHOR INFORMATION Corresponding Author * E-mail: [email protected]

ACKNOWLEDGMENT This work was supported by a grant from Geoscience Australia. We appreciate helpful conversations with Patrick V. Brady. We would also like to extend our appreciation to Mr. Bob Webb for his help and support towards conducting the laboratory measurement.


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A pH-Resolved Wettability Alteration: Implications for CO2-Assisted

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