Wettability Of Calcite Research Articles

The effect of low salinity water on wettability alteration of oil-wet calcite surfaces

To shed light on the chemical and physical aspects of low-salinity (LS) water flooding to enhance oil recovery, we explored the impact of the brine salinity on the modifications of the oil-calcite interface using a multi-technique surface science approach based on FTIR, AFM, XPS, and Contact angle measurements. Our findings reveal that Nujol-model oil adsorbs on fresh-cleaved CaCO3 (104) surface and initially forms a continuous film. Chemical and morphological surface characterizations were performed on oil-wet calcite, followed by their conditioning with formation (FW), demineralized (DW), and low salinity water (LS25, LS50, LS75, and LS100). The oil removal was quantified by semi-quantitative FTIR analysis and was found to vary from ∼20 % for FW up to ∼81 % for LS75 conditioning. In the investigated experimental conditions the fresh-cleaved calcite surface is most efficiently converted from oil-wet to water-wet when conditioned with LS75 brines. Significant surface wettability alterations were observed for LS 75 brines as contact angle measurements were found to reach a minimum contact angle of ∼18°. The changes in calcite wettability correspond to the formation of fragmented oil islands and calcite step bunches, the signature of surface dissolution, and changes in the oil-calcite chemical interactions. A model for Nujol adsorption and its detachment from the calcite surface was proposed for oil removal, competitive mechanisms related to the brine chemical composition are discussed.

Effect of ethylene oxide groups on calcite wettability reversal by nonionic surfactants: An experimental and molecular dynamics simulation investigation

HypothesisEthoxylated nonionic surfactants are promising candidates for enhanced oil recovery (EOR) from oil-wet carbonate reservoirs due to their ability to reverse the mineral wettability. The wettability-reversal efficiency increases with the number of the ethoxy (EO) groups in the surfactant molecule. MethodologyContact angle measurements, scanning electron microscopy (SEM) and molecular dynamics (MD) simulations were combined to investigate the wettability reversal of an oil-wet calcite by three ethoxylated nonionic surfactants with 1, 4 and 8 EO groups, respectively, to directly probe the role of the EO groups and to uncover the molecular mechanism responsible for the wettability reversal. FindingsBoth experiments and simulations consistently show a clear correlation between the number of EO groups and the wettability reversal efficiency of the surfactants, whereby the higher number of EO groups results in greater degree of wettability reversal. This is due to 1) the more hydrophilic surfactant headgroup weakening the carboxylate interactions with the surface by expanding the surface-adjacent water layer, and 2) the physically larger surfactant molecule attracting the carboxylates more strongly, thus aiding in their removal from the surface.

The reversal of carbonate wettability via alumina nanofluids: Implications for hydrogen geological storage

Underground hydrogen storage (UHS) has been recognized as a key enabler of the industrial-scale implementation of a hydrogen-based economy. However, the efficiency and storage capacity of hydrogen (H2) in carbonate aquifers can be influenced by the presence of organic acids. Nevertheless, the existing literature contains few investigations of H2/calcite/brine wettability and the influence of organic acids on H2 storability in carbonate reservoirs. Therefore, the present study examines the influence of stearic acid on the dynamic H2/brine wettability of calcite substrates (as a proxy of carbonate formation) under various geological conditions (0.1–20 MPa at 323 K), equilibrated in 10 wt% NaCl brine. In addition, the application of various alumina nanofluid concentrations (0.05, 0.1, 0.25, and 0.75 wt%) is evaluated under the same experimental conditions for enhancing the organic-aged calcite wettability. The results demonstrate a significant impact of stearic acid on the dynamic (advancing and receding) contact angles of the calcite substrates, thereby resulting in a shift from intermediate water-wet to H2-wet conditions, representing an unfavorable state for H2 geological storage. Conversely, the application of alumina nanofluid on the organic-aged calcite substrate enhances the H2/brine/calcite wettability towards an intermediate water-wet state, which is more favorable for H2 residual trapping in carbonate formations. The optimal concentration of alumina nanofluid for the wettability modification of the organically aged calcite samples is found to be 0.25 wt%. These findings highlight the influence of organic acid contamination and the potential of alumina nanofluid application in enhancing H2 geo-storage conditions in carbonate reservoirs.

Experimental and theoretical investigation of the impact of crude-oil on the wettability behavior of calcite and silicate due to low salinity effect

Wettability alteration is recognized as the main responsible mechanism for enhanced oil recovery during low salinity water flooding (LSWF) in both carbonates and sandstones. However, there is still a lack of understanding about the possible role of oil type on rock wettability alteration during LSWF. In the current study, contact angle (CA), interfacial tension (IFT), and zeta potentials for both oil/brine and rock/brine interfaces are measured for rock/brine/crude oil systems in a wide range of salinity of seawater. Two different crude oil samples and both calcite and silicate as good end-members of carbonate and sandstones are investigated. For oil A, the CA decreases with brine dilution; however, for oil B, the CA showed almost the opposite trend vs. salinity. The increased water-wetness of silicate compared to calcite surface was more highlighted in lower salinity. The results of zeta potentials showed that diluting seawater (SW) reduced the zeta potentials of rock/brine and oil/brine in all systems. The changes in zeta potential suggest that more dilution shall lead to more water-wetness, which is not in agreement with the CA behavior of two minerals in the case of crude oil B. Based on the augmented Young-Laplace equation, it was demonstrated that there is a good correlation between the IFT and the wettability, especially for calcite minerals. To shed light on the competition between the IFT and the EDL force, a comprehensive model was created to predict the CA results by coupling the surface complexation model (SCM), the DLVO theory, and the Young-Laplace equation. The coupled model successfully predicted the experimental contact angle for both crude oil and rock samples. Analyzing the disjoining pressure curves showed that due to the attractive EDL forces of calcite rocks, the oil/brine IFT solely controls the calcite wettability behavior with salinity. However, for silicate substrates, the high repulsive EDL forces are the main reason for the rock water-wetness at low salinity brines.

Effect of oil carboxylate hydrophobicity on calcite wettability and its reversal by cationic surfactants: An experimental and molecular dynamics simulation investigation

The oil-wet state of carbonate reservoirs presents a serious challenge for oil recovery. While cationic surfactants are able to reverse the wettability, their efficiency depends on the oil composition, particularly on the carboxylates as the main surface-active compounds. In this study, calcite surface was aged by two distinct carboxylates: a shorter, less hydrophobic octanoate and a more hydrophobic stearate. The surface wettability and its reversal by a quaternary ammonium cationic surfactant were studied both experimentally by contact angle measurements and Scanning Electron Microscopy (SEM) imaging, and by molecular dynamics (MD) simulations. Both simulations and experiments show that aging with the more hydrophobic stearates yields more strongly oil-wet surfaces, whose wettability is more difficult to reverse by the cationic surfactant, than aging with octanoates. While the surfactant ultimately reverses the wettability in both cases, significantly higher surfactant concentration is required for the stearate-aged calcite. The difference in the wettability can be rationalized by the greater hydrophobicity of the stearate, which strengthens both the surface adsorption and attraction of the non-polar oil phase.

Interactions of common scale inhibitors and formation mineral (calcium carbonate): Sorption and transportability investigations under equilibrium and dynamic conditions

Formation and deposition of mineral scales pose a serious threat to the safety and integrity of oilfield operations. Scale inhibitor chemicals have been widely employed to control scale threat and enhance production efficiency. The inhibitor-formation mineral interaction together with inhibitor transport behavior play significant roles in the design and optimization of oilfield inhibitor treatment. However, limited studies have been reported to investigate the principles dictating the inhibitor-mineral interaction under both equilibrium and dynamic conditions. Moreover, there are few studies focusing on the inhibitor transport at a lower inhibitor concentration. In this study, a systematic evaluation of the physicochemical nature of inhibitor-formation mineral interactions was conducted with a focus on lower inhibitor concentrations (below 50 mg L−1) by adopting two common oilfield inhibitors of diethylenetriamine pentamethylene phosphoric acid (DTPMP) and phosphino-polycarboxylic acid (PPCA). The formation mineral employed in this study is calcium carbonate (calcite). Both equilibrium and the kinetics aspects of inhibitor sorption behavior have been studied experimentally via static batch and dynamic column apparatus. It was found that the adsorption capacity of calcite for DTPMP is higher than that of PPCA. Laboratory fixed-bed column transport experiments were carried out at different physicochemical conditions of initial inhibitor concentration, ionic strength, temperature, flow rate and calcite particle size. Results indicate that an increase in both DTPMP and PPCA concentration can expedite inhibitor transport and a high initial DTPMP concentration could significantly affect the retention of DTPMP in the calcite porous medium. Ionic strength can result in a higher transportability in calcite medium for both inhibitors. Change in temperature has no significant impact on inhibitor transport. The flow rate has a considerable influence on the dispersion coefficient due to elevated mechanical dispersion at a higher flow rate for DTPMP. The calcite particle size can also impact inhibitor adsorption due to the change in surface area. Furthermore, adsorption of PPCA can subject the calcite surfaces more hydrophilic than DTPMP, which can affect the mobility of inhibitor in calcite medium. Atomic force microscopy characterization results confirmed that the wettability of calcite was increased through adsorption of DTPMP and PPCA inhibitor. This study provides deep insights into the sorptive behavior and transportability of DTPMP and PPCA inhibitors in calcite porous medium.

Surfactant-induced wettability reversal on oil-wet calcite surfaces: Experimentation and molecular dynamics simulations with scaled-charges

HypothesisSurfactant flooding is the leading approach for reversing the wettability of oil-wet carbonate reservoirs, which is critical for the recovery of the remaining oil. Combination of molecular dynamics (MD) simulations with experiments on simplified model systems can uncover the molecular mechanisms of wettability reversal and identify key molecular properties for systematic design of new, effective chemical formulations for the enhanced oil recovery. Experiments/SimulationsWettability reversal by a series of surfactant solutions was studied experimentally using contact angle measurements on aged calcite chips, and a novel MD simulation methodology with scaled-charges that provides superior description of the ionic interactions in aqueous solutions. FindingsThe MD simulation results were in excellent agreement with the experiments. Cationic surfactants were the most effective in reversing the calcite wettability, resulting in complete detachment of the oil from the surface. Some nonionic surfactants also altered the wettability, but to a lesser degree, while the amphoteric and anionic surfactants had no effect. From the tested cationic surfactants, the double-tailed one was the least effective, but the experiments were inconclusive due to its poor solubility. Contributions of specific interactions to the wettability reversal process and implications for the design and optimization of surfactants for the enhanced oil recovery are discussed.

Experimental Investigation of the Effect of Acid and Base on Wettability Alteration of a Calcite Surface

Wettability alteration toward a favorable wetting condition is one major mechanism of enhancing oil recovery in carbonates. Obtaining the desired wettability stipulates that a clear understanding of the original wetting properties of the rock surface be provided. In fact, the aim of this study is to elucidate the effect of acid and base upon the wettability alteration of a calcite surface by investigating the individual effects of an organic acid (stearic acid) and a base (N,N-dimethyldodecylamine, N,N-DMDA) at different concentrations as well as their combinations on calcite wetting properties. Contact angle, ζ-potential, Fourier transform infrared spectroscopy, and thermogravimetric analysis (TGA) were conducted to determine changes in wetting properties of the calcite surface. Moreover, interfacial tension (IFT) measurements were used to evaluate the interfacial activity of the model oil systems. Overall, the results revealed that by increasing the acid concentration, wettability of a calcite surface shifted toward more oil-wetness and adsorption of stearic acid on a calcite surface increased. Treating calcite surfaces with the base revealed that a low concentration of N,N-DMDA was able to shift the calcite wettability from a water-wet state to a slightly oil-wet state. In addition, TGA results showed low adsorption of the base with a high surface area occupied by the base molecule, indicating a horizontal orientation of the base on the calcite surface. For acid–base mixtures, at a constant acid concentration, the wettability alteration toward oil-wetness increased in the presence of the base, as the base-to-acid ratio increased up to 1, as a result of which oil-wetness decreased. Moreover, IFT measurements indicated lower IFT of acid–base mixtures compared to those of individual acidic and basic model oil solutions, which could be attributed to the synergistic effect between the acid and base by forming acid–base complexes. The presence of the base hindered acid adsorption on the calcite surface. However, the basic component could contribute to wettability alteration by forming acid–base complexes. These complexes could adsorb on the calcite surface and affect its wetting preferences. In addition, the base molecules may adsorb on the calcite surface at high base-to-acid ratios. The results suggested that the ratio of base to acid would determine the contribution of acid molecules, base molecules, and acid–base complexes in wettability alteration of calcite surfaces. Hence, possible mechanisms of wettability alteration by acid–base combinations were proposed at different base-to-acid ratios.

Synergistic Effect of Nanofluids and Surfactants on Heavy Oil Recovery and Oil-Wet Calcite Wettability.

In recent years, unconventional oils have shown a huge potential for exploitation. Abundant reserves of carbonate asphalt rocks with a high oil content have been found; however, heavy oil and carbonate minerals have a high interaction force, which makes oil-solid separation difficult when using traditional methods. Although previous studies have used nanofluids or surfactant alone to enhance oil recovery, the minerals were sandstones. For carbonate asphalt rocks, there is little research on the synergistic effect of nanofluids and surfactants on heavy oil recovery by hot-water-based extraction. In this study, we used nanofluids and surfactants to enhance oil recovery from carbonate asphalt rocks synergistically based on the HWBE process. In order to explore the synergistic mechanism, the alterations of wettability due to the use of nanofluids and surfactants were studied. Nanofluids alone could render the oil-wet calcite surface hydrophilic, and the resulting increase in hydrophilicity of calcite surfaces treated with different nanofluids followed the order of SiO2 > MgO > TiO2 > ZrO2 > γ-Al2O3. The concentration, salinity, and temperature of nanofluids influenced the oil-wet calcite wettability, and for SiO2 nanofluids, the optimal nanofluid concentration was 0.2 wt%; the optimal salinity was 3 wt%; and the contact angle decreased as the temperature increased. Furthermore, the use of surfactants alone made the oil-wet calcite surface more hydrophilic, according to the following order: sophorolipid (45.9°) > CTAB (49°) > rhamnolipid (53.4°) > TX-100 (58.4°) > SDS (67.5°). The elemental analysis along with AFM and SEM characterization showed that nanoparticles were adsorbed onto the mineral surface, resulting in greater hydrophilicity of the oil-wet calcite surface, and the roughness was related to the wettability. Surfactant molecules could aid in the release of heavy oil from the calcite surface, which exposes the uncovered calcite surface to its surroundings; additionally, some surfactants adsorbed onto the oil-wet calcite surface, and the combined role made the oil-wet calcite surface hydrophilic. In conclusion, the study showed that hybrid nanofluids showed a better effect on wettability alteration, and the use of nanofluids and surfactants together resulted in synergistic alteration of oil-wet calcite surface wettability.

Impact of temperature and SO42- on electrostatic controls over carbonate wettability

The use of modified salinity and modified composition brines (MSMC), referred to as smart water, to alter carbonate surface wettability at different temperatures has gained enormous popularity. However, an effective way to quantify the geochemical, thermodynamic and electrostatic factors responsible for wettability alteration have still not been fully developed. In this work, a surface complexation model (SCM) based on geochemical and thermodynamic interactions at calcite and oil surfaces was used to investigate the effect of temperature, pH, and sulfate on electrostatic interactions. SCM’s for calcite and oil surfaces were validated against zeta potential data at high temperatures and used to interpret improved oil recovery data from spontaneous imbibition experiments. The SCM was correlated to calcite wettability through the calculation of the bond product sum (BPS); a measure of the strength of the electrostatic bond linkages between calcite and oil surfaces. Increasing temperature increased the zeta potential towards more positive values for positive polarities and towards more negative values for negative polarity at both the calcite and oil surfaces. BPS decreased with increasing temperature due to the weakening of [>CO 3 – ][‒NH + ] electrostatic bonds, indicating an increase in water-wetness, consistent with the existing literature. Increasing the sulfate ion concentration in seawater brine reduced the BPS, indicating an increase in water wetness. This was attributed to the reduction in [>CaOH 2 + ][‒COO – ] associated bonds as sulfate concentration increased. Spontaneous imbibition experiments confirmed the BPS analysis, whereby oil recovery increased as sulfate concentration and temperature increased. • A surface complexation model was developed which describes high temperature calcite-brine-oil interfaces. • Increasing temperature decreased oil-calcite electrostatic bonding and increased water wetness in calcite rocks. • Increasing temperature enhanced brine imbibition into limestone, as predicted by the surface complexation model. • Sulfate concentration and brine pH also influenced calcite wettability.

Atomistic Molecular Dynamics Simulations of Surfactant-Induced Wettability Alteration in Crevices of Calcite Nanopores

Wettability alteration is an important mechanism in surfactant-facilitated enhanced oil recovery (EOR) in oil-wet carbonate reservoirs. An in-depth understanding of how surfactants influence the wettability of calcite surfaces is of crucial importance. In this study, atomistic molecular dynamics simulations were used to elucidate how the nonionic and anionic surfactants influence the wettability at the corners of angular calcite pores. A multicomponent oil model was constructed based on a chemical analysis of an unconventional reservoir crude oil. It was found that the inclusion of the calcite surface water layer caused a significant decrease in the attraction between the surface and the surfactant molecules from hundreds of kJ/mol to essentially zero. The surface water layer is therefore critical for an accurate description of calcite wettability. Simulated flooding of the oil-filled calcite pore with both types of surfactants was compared to that with blank brine. It was found that the tested surfactants alter the wettability of the calcite surface mainly by hydrophobic interactions with the adsorbed polar oil components and by weakening the interactions between polar and nonpolar oil components. The wettability alteration resulted in a 20–30° reduction in contact angles, while the ratio of the polar-to-nonpolar oil components within the pore decreased by approximately 50% by the surfactants as compared to just brine. The results presented in this work can provide guidance for selection of the most effective surfactants for oilfield applications.

Mechanism of wettability alteration of the calcite {101[combining macron]4} surface.

To understand the mechanism of wettability alteration of calcite, a typical mineral in oil reservoirs, the interactions of deionized water and brine (with different compositions) with the calcite {101[combining macron]4} surface are investigated using a combination of molecular dynamics and first-principles simulations. We show that two distinct water adsorption layers are formed through hydrogen bonding and electrostatic interactions with the calcite {101[combining macron]4} surface as well as hydrogen bonding between the water molecules. These highly ordered water layers resist penetration of large stable Mg2+ and Ca2+ hydrates. As Na+ and Cl- hydrates are less stable, Na+ and Cl- ions may penetrate the ordered water layers to interact with the calcite {101[combining macron]4} surface. In contact with this surface, Na+ interacts significantly with water molecules, which increases the water-calcite interaction (wettability of calcite), in contrast to Cl-. We propose that formation of Na+ hydrates plays an important role in the wettability alteration of the calcite {101[combining macron]4} surface.

Impact of Acid and Base Numbers and Their Ratios on Wettability Alteration of the Calcite Surface

Alteration of rock wetting preference toward a more favorable wetting state has been identified as the primary mechanism of oil recovery from intermediate and oil-wet carbonate rocks. In order to produce a favorable wetting state, it is critical to have a clear picture of the initial wetting properties of the rock surface. This study aimed to improve the understanding of carbonate wettability by examining the impact of acid, base, and their mixture on wettability of calcite surfaces using different analytical tools (contact angle measurements, zeta potential test, Fourier transform infrared spectroscopy, interfacial tension measurements, and fluorescence ultraviolet spectroscopy). The acid number (AN) and the ratio of the basic component (quinoline) to the acidic component (stearic acid) were systematically varied in model oil solutions to elucidate the effect of simultaneous presence of the acid and base on the wettability alteration process. The results showed that as the acid concentration increases, the wettability alteration toward the oil-wet state is enhanced. However, the impact of the base was significant at high concentrations, where the wettability was changed toward the neutral state. Addition of the basic compound to the acidic model oil hindered the impact of stearic acid on wettability alteration. Although the impact of the basic component on wettability alteration of calcite seems to be weaker than that of the acidic component, presence of the base can alter the wetting characteristics of the surface. Acid and base concentrations and their ratio dictate the extent of calcite wettability alteration. Slight impact of the base on the wettability alteration process was observed for a system with an AN of 0.25. However, at higher ANs, an increase in the base number (BN) to AN ratio from 0 to 1 resulted in a remarkable reduction in the contact angle; while the contact angle increased again when the BN to AN ratio was 4. Further investigations (for systems with AN = 1) revealed that at the BN to AN ratio of 0.25 and 1, adsorption of the basic component on the surface was unlikely to happen. Formation of an acid–base complex could hinder the access of stearate ions to the calcite surface. At the BN to AN ratio of 1, the quinoline concentration was equal to that for stearic acid, which may enhance the acid–base interactions; hence, more stearic acid would be involved in acid–base complexes. However, once the base concentration became higher than the acid concentration (BN to AN = 4), an excess amount of the base, which was not involved in the complex mixtures with acid molecules, might adsorb on the surface.

Microorganisms\u2019 effect on the wettability of carbonate oil-wet surfaces: implications for MEOR, smart water injection and reservoir souring mitigation strategies

In upstream oil industry, microorganisms arise some opportunities and challenges. They can increase oil recovery through microbial enhanced oil recovery (MEOR) mechanisms, or they can increase production costs and risks through reservoir souring process due to H2S gas production. MEOR is mostly known by bioproducts such as biosurfactant or processes such as bioclogging or biodegradation. On the other hand, when it comes to treatment of reservoir souring, the only objective is to inhibit reservoir souring. These perceptions are mainly because decision makers are not aware of the effect microorganisms’ cell can individually have on the wettability. In this work, we study the individual effect of different microorganisms’ cells on the wettability of oil-wet calcite and dolomite surfaces. Moreover, we study the effect of two different biosurfactants (surfactin and rhamnolipid) in two different salinities. We show that hydrophobe microorganisms can change the wettability of calcite and dolomite oil-wet surfaces toward water-wet and neutral-wet states, respectively. In the case of biosurfactant, we illustrate that the ability of a biosurfactant to change the wettability depends on salinity and its hydrophilic–hydrophobic balance (HLB). In distilled water, surfactin (high HLB) can change the wettability to a strongly water-wet state, while rhamnolipid only changes the wettability to a neutral-wet state (low HLB). In the seawater, surfactin is not able to change the wettability, while rhamnolipid changes the wettability to a strongly water-wet state. These results help reservoir managers who deal with fractured carbonate reservoirs to design a more effective MEOR plan and/or reservoir souring treatment strategy.

Wettability of calcite under carbon storage conditions

Knowledge of interfacial properties, including both fluid-fluid interfacial tension and mineral wettability is essential for accurate simulation of carbon dioxide storage in geological formations. In this context, carbonate reservoirs, especially saline aquifers, are of great interest due to their vast storage capacities; therefore, it is imperative to attain a thorough understanding of their wettability under the high-pressure, high-temperature (HPHT) conditions of CO2 storage. To this purpose, contact angles have been measured for the system CO2 + NaHCO3(aq) + calcite under HPHT conditions. Calcite is representative of limestone minerals and the brine chemistry and molality (1 mol·kg−1) have been chosen to inhibit dissolution reactions. Both static (sessile drop) and dynamic (tilting plate) contact angle measurements were carried out under reaction-free conditions at temperatures from (298 to 373) K and at pressures up to 30 MPa. The influences of surface roughness and cleanliness have also been addressed in this study. We found that calcite is mainly brine-wet, but it can turn intermediate-wet or even weakly CO2-wet at intermediate pressures (around 10 MPa) and low temperature conditions (around 300 K). The results presented in this work may prove useful for characterizing the wettability of a wide variety of calcite (limestone) surfaces that one might expect to encounter in natural reservoirs.

Characterizing the Influence of Organic Carboxylic Acids and Inorganic Silica Impurities on the Surface Charge of Natural Carbonates Using an Extended Surface Complexation Model

In this work, we developed an extended surface complexation model (SCM) that successfully fits all tested ζ-potential data (63 in total) of synthetic calcite and three natural carbonates (Iceland spar, Indiana limestone, “SME” rock from a Middle East field) in brines with divalent ions in a wide range of ionic strengths (0.001–0.5 M). To develop this extended model, our previous reported SCM is first optimized by incorporating the ζ-potential of synthetic calcite in a wide range of ionic strength (0.001–0.5 M) along with previously published data for parameter refitting. The model is then applied to predict the surface charge of synthetic calcite in concentrated solutions up to 5 M NaCl to reveal the role of high salinity in calcite wettability. Eventually, the model is extended to fit the ζ-potential of natural carbonates by adding surface reactions for impurities such as silica and organic-based carboxylic acids. The coverage of the organic impurities is found to be essential for explaining why the ζ-po...

Wettability Alteration and Enhanced Oil Recovery Induced by Proximal Adsorption of Na+ , Cl− , Ca2+ , Mg2+ , and SO42− Ions on Calcite

The underlying mechanism of wettability alteration is vital for enhancement of oil recovery (EOR) by water flooding in carbonate reservoirs, such as calcite rock. Based on first-principles molecular dynamics simulations and core-flooding measurements, the authors find that proximal adsorption of ions in brine affects the wettability of calcite: Some ions primarily disturb the interfacial water structure, while others modify the effective surface charge, thus inhibiting and enhancing oil recovery respectively. This study provides needed insight into the physics of wetting at the atomic scale for EOR.

Understanding the Wettability of Calcite (CaCO3) Using Higher Spatial Resolution

Wettability alteration of carbonate rocks from an oil-wet state to a water wet or mixed-wet state during water flooding is known to enhance the recovery of oil from the reservoirs. Previously, the wettability of porous mediums has been extensively investigated using numerous macroscopic methods. Among those, the contact angle is a highly employed method for wettability measurements; however, this technique, because of its lower spatial resolution, fails to provide a complete chemical understanding of all the factors affecting the reservoir wettability. In an attempt to overcome this, we employed a multiscale approach involving macro-, micro-, and nanoscopic analytical techniques to investigate the wettability of calcite. Studies were performed by aging two different planes of freshly cleaved calcite in ambient atmosphere and with deionized (DI) water. Contact angle measurements and AFM force profiles were recorded at the macroscale and nanoscale, respectively. Wettability transition was observed from super hydrophilic to hydrophobic nature in ambient atmosphere and super hydrophilic to hydrophilic nature in DI water. When AFM studies were performed on samples aged in DI water there were always patches of water present, which were observed only at the nanoscale. These water patches affect the contact angle measurements and make the macroscopic wettability results inherently ambiguous. This work has shown that the contact angle measurements should not be taken as the absolute measurement of wettability.

Understanding Calcite Wettability Alteration through Surface Potential Measurements and Molecular Simulations

Mineral wettability and wettability alteration are important factors that determine the distribution and mobility of oil during the recovery process. Because wettability is dependent on many factors (e.g., hydrocarbon composition, mineralogy, and pH), predicting mineral wettability is often difficult. The goal of this study is to look at changes that occur on the mineral itself, specifically changes in the surface structure and surface potential, using experimental methods complemented by quantum-mechanical calculations to better understand the molecular-level processes involved in wettability alteration. Nanoscale surface imaging is combined with Kelvin probe force microscopy (KPFM) to characterize changes in topography and surface potential for water-wet (hydrophilic) and oil-wet (hydrophobic) calcite surfaces, using the surfactant hexamethyldisilazane (NHSi2(CH3)6, HMDS) to render the calcite surface oil-wet. KPFM measurements show that HMDS adsorbs preferentially on step edges of the calcite surface a...

Wettability of nano-treated calcite/CO2/brine systems: Implication for enhanced CO2 storage potential

Nanofluids are proven to be efficient agents for wettability alteration in subsurface applications including enhanced oil recovery (EOR). Nanofluids can also be used for CO2-storage applications where the CO2-wet rocks can be rendered strongly water-wet, however no attention has been given to this aspect in the past. Thus in this work we presents contact angle (θ) measurements for CO2/brine/calcite system as function of pressure (0.1MPa, 5MPa, 10MPa, 15MPa, and 20MPa), temperature (23°C, 50°C and 70°C), and salinity (0, 5, 10, 15, and 20% NaCl) before and after nano-treatment to address the wettability alteration efficiency. Moreover, the effect of treatment pressure and temperature, treatment fluid concentration (SiO2 wt%) and the period of nano-treatment on the wettability of calcite is examined. We find that nano-treatment alters the wettability significantly i.e. intermediate-wet calcite turns strongly water-wet after treatment (e.g. at 20MPa and 50°C, θ=64° for intermediate-wet calcite, and θ=28° for nano-treated calcite). Consequently, pre-injection of nanofluids will significantly enhanced the storage potential. It was also found that the permanent shift in wettability after nano-treatment is a function of treatment conditions including temperature, pressure, and treatment duration time and that surfaces treated under high pressure and low temperature yield better wettability alteration efficiency. We point out that the change in wettability is attributed to the changes in surface properties of the nano-treated sample. The results of the study thus depict that nanoparticles can significantly enhance storage potential and de-risk storage projects.