Effect Of Wettability Alteration Research Articles

Nanocomposite synergy for enhanced oil recovery: Macro and micro analysis of CeO2/montmorillonite nanofluids in carbonate and sandstone reservoirs

Cerium (IV) oxide has shown great potential for serving as a mutually advantageous conjunction material when applied in a synergistic manner of use with other chemicals thanks to its oxygen storage capacity. Recently, many researchers have elaborated on novel synthesis methods for achieving nanocomposites (NCs) that combine inherent properties of nano-sized CeO2 with those of montmorillonite, as a low-cost base substance. CeO2/Montmorillonite nanocomposite synthesized by application of an environmentally friendly reducing and stabilizing agent. The success of the synthesis was verified by analytical techniques including Field-Emission Scanning Electron Microscopy, Thermo-Gravimetric analysis, Energy-Dispersive X-ray Spectroscopy and Mapping, X-Ray Diffraction analysis, Fourier-Transform Infrared spectroscopy. Nanofluids were prepared by dispersing the synthesized NCs, at different concentrations as aqueous colloidal solutions and then studied for investigating the nanofluid colloidal stability. Experimental studies were undertaken on the nanofluid functioning subjects of the fluid/fluid and fluid/fluid/rock interactions area in both macro and micro scales. Macro investigations of interfacial tension and wettability alteration and also micro-analysis of microfluidic injections with proper visualizations of created effects within pore structures were carried out. The results confirmed the proper synthesis of the NC and its stability in water-based nanofluids. CeO2 nano clays showed nearly 33 % optimization of the interfacial tension (IFT) (i.e., IFT decreased from the initial value of 27 to 18 mN/m at the NC concentration of 1000 ppm). However, their effect on the alteration of wettability was significant. Indeed, at the optimum concentrations, the contact angle decreased from 151° to 19.38° at the concentration of 500 ppm for carbonate lithology (87.1 % optimization) and also it decreased from 135.5° to 18.73° at the concentration of 1500 ppm for sandstone lithology (86.1 % optimization). The effect of wettability alteration for carbonate rocks was reported to be high enough for changing the wettability to a strong water-wet state while the wettability alteration for sandstone lithology was measured to be low. Both wettability alteration studies and micro visualizations validated the strong and low wettability alteration for carbonate and sandstone lithology systems. Also, the emulsion analysis was carried out on the micro-scaled images of the pores and throats with their containing fluids by a new method of color saturation investigation which showed a promising new emulsion analysis method for micro-scaled experiments.

Investigating the impact of wettability heterogeneity on tertiary oil recovery by foam flooding: A macroscopic visualization study

The gas injection is a widely used technique for improving oil recovery; however, in reservoirs with heterogeneous characteristics, the injection of gas in the form of foam is more promising. Due to the heterogeneous nature of oil reservoirs, we compared the foam flow performance at the tertiary mode with that of gas injection using an anionic surfactant AOS and a cationic surfactant CTAB. Glass bead packed models were used with different patterns of wettability heterogeneity including oil-wet, water-wet, stripe, layer, and quadrant. While gas injection in heterogeneous models produced only 10–15% of the waterflood residual oil, foam injection could control the gas mobility and recover almost 30–50% of the residual oil. The most stable foam was formed in the water-wet porous medium whereas the lowest stable foam was visually observed in the oil-wet porous medium due to the presence of more residual oil. However, the synergistic effect of wettability alteration and piston-wise displacement of the foam front improved oil recovery even in the oil-wet medium compared to the gas injection scenarios. Among all heterogeneous models, the highest oil recovery was achieved in the layer model and its oil recovery profile was compatible with that of the water-wet homogeneous model. Conversely, we found that positioning an oil-wet layer strongly declined foam flow performance as was observed in both layer and quadrant models. Compared to the AOS foam, the CTAB foam was more stable and efficient in recovering waterflood residual oil in the models under study.

Effects of temperature and nanofluid type on the oil recovery from a vertical porous media in antigravity fluid injection

Recent researches indicate that the injection of nanofluid solutions into oil reservoirs enhances oil recovery, but the impact of key important parameters such as antigravity fluid injection has not yet been well understood. In current experimental investigation, effects of temperature and antigravity injection on the enhancement of oil recovery was studied. Additionally, effects of wettability alteration, interfacial tension, and viscosity were investigated. Pure water, TiO2, CuO, and γ-Al2O3 nanofluids were considered as injected fluid. During the antigravity fluid injection process, decreasing the capillary number enhanced the oil recovery. This increment for pure water, TiO2, CuO, and γ-Al2O3 nanofluids injection was 42.8%, 65.7%, 73.5%, and 75.7%, respectively. Compared to the gravity-aligned injection, these results show enhancement by up to 18.25%, 19.7%, 17.5%, and 23.7%. Moreover, for injection in antigravity direction when water, TiO2, CuO, and γ-Al2O3 nanofluids injected at 90 °C oil recovery enhanced by 7.8%, 5.2%, 3.7%, and 2.75%, respectively, compared to the results obtained for injection at 25 °C. Besides, oil recovery enhanced substantially by interfacial tension reduction when using nanofluids instead of water. For instance, the maximum recovery belongs to γ-Al2O3 nanofluid by 43.5% as the interfacial tension reduced from 45.03 mN/m for oil-water to 2.36 mN/m for oil and γ-Al2O3 nanofluid. Furthermore, increasing the injection temperature from 25 °C to 90 °C reduced the interfacial tension. This reduction for water injection was 15.8%, and 21.2% for γ-Al2O3 nanofluid injection.

Effects of CO2 and surfactants on the interface characteristics and imbibition process in low-permeability heavy oil reservoirs

Due to the poor physical properties and low flowing capability of crude oil in low-permeability heavy oil reservoirs, fracturing is generally required for effective development. Imbibition is considered an important development method for low-permeability and tight reservoirs after fracturing. In this paper, the imbibition efficiency of different concentrations of surfactant solutions and different CO2 pressures in low-permeability heavy oil reservoirs were studied, the oil-water interfacial tension (IFT) and contact angle (CA) of the imbibition process were tested, and the mechanism of improved oil recovery (IOR) was obtained by the modified NB−1. In addition, the effects of permeability and oil viscosity changes on imbibition efficiency were also investigated. The results show that the imbibition recovery of heavy oil increases with increasing surfactant solution concentration, and surfactants can reduce IFT and alter wettability. The oil recovery can be enhanced by 10.87% with the addition of surfactants. At the beginning of imbibition, the NB−1 value is negative, and the imbibition process is cocurrent imbibition driven by gravity. Then, the NB−1 value soon becomes positive, and the capillary force becomes the driving force of the imbibition process. As the CO2 pressure increases, the imbibition recovery increases. When the system pressure is 8 MPa, the imbibition recovery reaches 29.8%. CO2 can reduce the oil viscosity and IFT as well as strengthen the wettability alteration effect through dissolution and diffusion, thus enhancing the flowing capability of heavy oil. The imbibition recovery increases with increasing core permeability (50–200 mD), but the increase gradually decreases. In addition, imbibition recovery decreases with increasing oil viscosity, and the key factor for imbibition in low-permeability heavy oil reservoirs is to improve the flowing capability of the heavy oil.

A Review of the Seepage Mechanisms of Heavy Oil Emulsions during Chemical Flooding

Chemical flooding plays an important role in enhancing oil recovery due to many reasons, including the viscosity-increment effect of polymer, wettability alteration effect of surfactant, and the formation of emulsions, which have been known to effectively increase the swept area and oil displacement efficiency, hence increasing heavy oil recovery. Laboratory tests and pilot trials of alkali–surfactant–polymer (ASP) injection show that the oil recovery of the emulsified system is 5% more than the cases where no emulsions existed. Therefore, it is of great significance to study heavy oil emulsions and its field application for enhanced heavy oil recovery. This paper discusses a thorough overview of the most fundamental ASP flooding mechanisms, along with some examples of laboratory experiments and field trials. In addition, the formation conditions and the interfacial characteristics of heavy oil emulsions are also discussed, mainly ASP flooding, and then the seepage mechanisms of these emulsions are investigated. The relationship between the formation of heavy oil emulsions and the enhanced heavy oil recovery effect by chemical flooding is discussed through core flooding experiments at the reservoir temperature and some field pilots to reach the optimum heavy oil recovery.

Efficiency of ionic liquid/polymer flooding combined with smart water injection on oil recovery through secondary and tertiary patterns using Iranian carbonate rock

The current investigation utilizes direct injection of modified smart water (SW) after oil flooding stage (secondary oil recovery process) instead of injecting the solution after water flooding (tertiary oil flooding). Before performing these types of core flooding experiments, viscosity, interfacial tension (IFT), and wettability alteration besides the effect of ionic liquids (ILs) on the IFT reduction are investigated at the presence of hydrolyzed polyacrylamide (HPAM) dissolved in SW. The results show the oil recovery of 63.5% by injecting SW/polymer while individual injection of water leading the oil recovery of 23.9% based on original oil in place (OOIP). Besides, further core-flooding experiments reveal that injecting SW/polymer solution modified by IL-based surfactants (SWPIL) enhances the recovery to 69.8 and 73.9% based on OOIP for 1-dodecyl-3-methylimidazolium chloride ([C12mim][Cl])) and 1-octadecyl-3-methylimidazolium chloride ([C18mim][Cl])) during the secondary stage. Finally, performing core-flooding experiments with a soaking time of 21 days reveal 87.0 and 89.3% of ultimate oil recovery which can be correlated to IFT reduction while the remained portions (13 and 10.7%) belong to the wettability alteration effect.

Surfactant enhanced imbibition in carbonate reservoirs: Effect of IFT reduction and surfactant partitioning

A majority of carbonate reservoirs are preferably oil-wet or intermediate wet. Spontaneous imbibition represents an important mechanism to enhance oil production. Targeting an oil-wet carbonate reservoir with high temperature and high salinity, several surfactant formulations were investigated to improve oil production by imbibition, focusing on the capacity in interfacial tension (IFT) reduction and surfactant partitioning in water and oil phases in addition to dominant wettability alteration effect. Oil production potentials using different surfactants were evaluated by spontaneous imbibition in Amott cells at 95 ​°C. A base case imbibition test was conducted using a high salinity water with IFT value of 15.2 ​mN/m and an oil-wet carbonate core, and the oil production was 6.4% of oil originally saturated in core. Reducing the oil-water IFT to 10° ​mN/m magnitude achieved 4% incremental oil production beyond base case. When the IFT was further reduced to 10 −1 ​mN/m magnitude, the incremental oil production reached 10%. For the case of water-wet core and at the same IFT range, the incremental oil production was 13%. When the IFT was reduced to 10 −2 ​mN/m, the incremental oil production was up to 17% for the tests using oil-wet cores, and up to 23% for the water-wet counterpart. When further reducing the IFT to ultra-low magnitude of 10 −3 ​mN/m, the oil production was close to that using the imbibition agents with IFT of 10 −2 ​mN/m magnitude. For surfactants with no obvious wettability alteration capacity, those surfactants with higher molecular fraction in oil phase and higher adsorption on rock surfaces could remove more oil from the pore wall, and yielded higher imbibition efficiency. This work systematically investigated the major effects of surfactant on oil mobilization during imbibition process, which can help for better understanding of chemical imbibition in carbonates. The findings will shed light on the selection of high performance imbibition agents for carbonate reservoirs.

Pore-doublet computational fluid dynamic simulation of the effects of dynamic contact angle and interfacial tension alterations on the displacement mechanisms of oil by low salinity water

Using our recently developed model, for the first time in the literature, the effect of fluid/fluid and rock/fluid interactions on the performance of Low Salinity Waterflooding (LSWF, as an Enhanced Oil Recovery process) at pore-doublet scale is investigated. The model is incorporated into OpenFOAM and both the Navier-Stokes equation for oil/water two-phase flow and the advection-diffusion equation for ion transport (at both fluid/fluid and rock/fluid interface) are solved via direct numerical simulation (DNS).The model is validated against imbibition and drainage pore-doublet experiments reported in the literature, and then applied to investigate the sole effect of wettability alteration as well as its coupled effect with interfacial tension (IFT) variations on the redistribution and transport of phases within the model. Different degrees of contact angle alteration, different trends of IFT variations reported in the literature, as well as different injection scenarios (secondary or tertiary) are considered.Simulation results show that in the case of high salinity water flooding (HSWF), IFT (within the range of 30 to 5 mN.m−1) has very limited effect on the residual oil saturation of the investigated model. For the case of HSWF in the oil-wet pore-doublet model (contact angle = 140°), significant amount of oil will be trapped in the small pores of the model. This residual oil cannot be produced in the absence of wettability alteration, no matter how much the IFT be reduced during LSWF (even as low as 0.1 mN.m−1). However in the absence of any IFT variation (IFT = 10 mN.m−1), the residual oil ganglia can be displaced with the sufficient degree of wettability alteration (contact angles below or equal to 30°). Nevertheless, in the presence of adequate contact angle reduction, fluid/fluid interactions (different IFT variation) can affect the outcome of the enhanced oil recovery. The LSWF performance boosts under appropriate degree of fluid/fluid and rock/fluid interactions as it leads to the coalescence of the detached or partially detached residual oil blobs and progress of chasing water front in both small and large pores of the doublets towards the downstream of the model. The results confirm the importance of fluid/fluid interactions such as IFT variation on such coalescence and dynamic LSWF, especially in the case of secondary LSWF.

Experimental investigation on the dominating fluid-fluid and rock-fluid interactions during low salinity water flooding in water-wet and oil-wet calcites

Low salinity water flooding (LSWF) has the potential to enhance the oil recovery by affecting the fluid-fluid and rock-fluid interactions. Therefore, a systematic investigation on the effect of initial wetting state (water-wet or oil-wet) of pure calcite is conducted to study the importance of these interactions on the effectiveness of LSWF. In the case of initially water-wet cores, more oil recovery efficiency is observed for more saline water cases. To shed light on the possible involved mechanisms, dynamic IFT, dynamic contact angle (CA), oil/brine and rock/brine surfaces zeta potentials, and effluent pH are measured. It is shown that the short-term effect of IFT reduction and long-term effect of wettability alteration toward neutral-wetness (due to change in the electric charge of the crude-oil/brine and calcite/brine) are the dominating recovery mechanisms. However, the oil recovery behavior of oil-wet cores is in the opposite direction of that of water-wet cores, which demonstrates the wettability dependency of the involved mechanisms. CA measurement shows that diluted sea water (dSW) has more ability to change wettability toward water-wetness. The zeta potential results show that as brine salinity reduces, both crude-oil and rock surfaces become more negatively charged. Therefore, the observed wettability alteration behavior with salinity reduction is attributed to larger repulsion between these surfaces at lower salinity. pH results suggest CO 3 2− ions are responsible to make calcite surface more negative with diluting SW brine. The oil recovery behavior is also a strong function of the initial wetting state. SW brine, recovered less oil and experienced an earlier breakthrough in an initially oil-wet core compared to an initially water-wet core. Unlike the previous case, dSW experienced higher ultimate oil recovery and almost the same breakthrough time in an initially oil-wet core compared to an initially water-wet core. The superior performance of the low salinity water in an oil-wet core is a result of the wettability alteration toward more water-wetness which triggers more piston-like advancement. • A systematic investigation on the contribution of different fluid-fluid and rock-fluid interactions in the oil recovery of low salinity water flooding in pure water-wet and oil-wet calcite rocks. • Dynamic IFT, dynamic contact angle, the zeta potential of both crude oil/brine and calcite/brine surfaces, and the effluent pH are measured to asses these interactions. • In the case of initially water-wet calcite, the oil recovery increases with the rise in the salinity. • In the case of oil-wet calcite, higher oil recovery achieved in the case of brine with lower salinity. • The effectiveness of low salinity water flooding, optimum salinity, ultimate oil recovery factor and breakthrough times are functions of rock wettability.

Microfluidic investigation of enhanced oil recovery: The effect of aqueous floods and network wettability

Rock wettability significantly influences underground oil extraction efficiency during enhanced oil recovery (EOR) processes. We experimentally examine the effect of wettability on oil recovery at pore-scale using microfluidics. Glass micromodels are used to mimic the quartz surfaces of hydrophilic porous rocks (such as sandstone), and their wettability is altered chemically with a hydrophobic coating to simulate oil-adsorbed hydrophobic surfaces. Comprehensive and systematic investigations are carried out, considering various crucial factors, namely crude oil components, flood type, as well as brine concentration and composition. A model oil, two crude oils with different chemical compositions, and various aqueous floods containing brine, surfactant, and brine-surfactant solutions are utilized. We record flood patterns and measure the global recovery factor to assess the effect of wettability alteration. Based on the pore-scale observations, water contact angles increase from tests with initially hydrophilic networks to those with hydrophobic ones. Two types of network designs are utilized in this study, a uniform network and a rock network. A layer of oil covers the pore walls and stays intact during the flood in hydrophobic rock networks. Generally, the recovery is lower in rock networks with smaller and dead-end pores. For brine floods, in water-wet networks, the recovery decreases with increasing ionic strength and divalent ions, whereas it is the opposite for the oil-wet ones. In the case of surfactant floods, presence of brine and its ionic strength have different effects on the recovery. One fundamental difference between the brine and surfactant floods proved to be the continuous recovery by the surfactant, i.e., the recovery does not reach a steady state. Finally, surfactant floods as the tertiary method of recovery proved to be more efficient than the brine-only for the experimental conditions explored.

Wettability alteration by Smart Water multi-ion exchange in carbonates: A molecular dynamics simulation study

Smart Water ions (Ca2+, Mg2+, and SO42−) have been found to alter the wettability of oil-wet calcite surfaces, however, the widely proposed multi-ion exchange mechanism has never been understood on a molecular scale. In this work, a new model calcite surface with steps and locally charged sites was developed, and its properties were studied by quantum chemical calculations and molecular dynamics simulations to investigate the origin of the oil-wetness and its reversal by the Smart Water ions at temperatures ranging from 300 to 400 K. The simulation results using the proposed surface model are consistent with experimental results reported in the literature, including the Smart Water ions acting as the potential determining ions, and the oil carboxylate adsorption causing oil-wetness. The wettability alteration involves initial surface binding of Ca2+, which facilitates adsorption of SO42−. The latter enables the detachment of the Ca2+-carboxylate complexes at elevated temperatures (>350 K) where the ionic hydration shells are weakened as suggested by the increased interaction energy from less than −100 to over −400 kJ/mol between Ca2+ and SO42−, rationalizing the observed temperature dependence of the Smart Water effect. Overall, the presented simulations with the newly developed model calcite surface provide important new insights into wettability alteration effect of Smart Water ions, which has important implications for the optimization of the injection brines for enhanced oil recovery.

Laboratory optimization of surfactant imbibition in high temperature and high salinity fractured reservoir

This paper focused on surfactant evaluation targeting the harsh reservoir conditions (high temperature and high salinity fractured reservoir). Six kinds of surfactants were selected and evaluated in terms of interfacial tension (IFT) and contact angle. . S-6 and S-7 presented the best potential ability in IFT reduction among all kinds of surfactant solutions, which were in the 10−2mN/m magnitude. The experiment results showed that the contact angle on oil-wet glass slide at the concentration of 0.2% S-6 was 58°, which is in water-wet region; while other surfactants cannot change the surface wettability. . Finally, the micromodel flooding tests were conducted using S-6, S-7 and S-8 to study both effects of wettability alteration and IFT reduction ability on EOR. The micromodel work was based on an oil-wet etched glass. Compared with S-7, the recovery increase of S-6 was about 12%, indicating that with the similar abilities of IFT reduction for surfactant solutions, the one with stronger wettability alteration ability could lead to a higher oil recovery. As a result, S-6 had better potential in providing higher oil recovery as an imbibition agent. Numerical simulation using UTCHEM suggested that with the increase of injection rate and the decrease of IFT, the imbibition recovery is increased.

Mechanism of active silica nanofluids based on interface-regulated effect during spontaneous imbibition

The ultra-low permeability reservoir is regarded as an important energy source for oil and gas resource development and is attracting more and more attention. In this work, the active silica nanofluids were prepared by modified active silica nanoparticles and surfactant BSSB-12. The dispersion stability tests showed that the hydraulic radius of nanofluids was 58.59 nm and the zeta potential was − 48.39 mV. The active nanofluids can simultaneously regulate liquid–liquid interface and solid–liquid interface. The nanofluids can reduce the oil/water interfacial tension (IFT) from 23.5 to 6.7 mN/m, and the oil/water/solid contact angle was altered from 42° to 145°. The spontaneous imbibition tests showed that the oil recovery of 0.1 wt% active nanofluids was 20.5% and 8.5% higher than that of 3 wt% NaCl solution and 0.1 wt% BSSB-12 solution. Finally, the effects of nanofluids on dynamic contact angle, dynamic interfacial tension and moduli were studied from the adsorption behavior of nanofluids at solid–liquid and liquid–liquid interface. The oil detaching and transporting are completed by synergistic effect of wettability alteration and interfacial tension reduction. The findings of this study can help in better understanding of active nanofluids for EOR in ultra-low permeability reservoirs.

Mechanistic study of the effects of dynamic fluid/fluid and fluid/rock interactions during immiscible displacement of oil in porous media by low salinity water: Direct numerical simulation

Low salinity waterflooding (LSWF) is a process in which by lowering the ionic strength and/or manipulation of the composition of the injection water, the long term equilibrium in oil/brine/rock system is disturbed to reach a new state of equilibrium through which the oil production will be enhanced due to fluid/fluid and/or rock/fluid interactions. In spite of recent advances in the simulation of the LSWF at core scale and beyond, there are very few works that have modelled and simulated this process at the pore scale specially using direct numerical simulation (DNS). As a result the effects of wettability alteration and/or Interfacial Tension (IFT) change on the distribution of the phases at pore scale, as well as dynamics and mechanisms of the oil displacements in porous media are neither thoroughly investigated nor well understood. With this objective, the present study takes into account modelling both rock/fluid (dynamic contact angle) and fluid/fluid (dynamic oil/water IFT as well as diffusion between high salinity and low salinity water) interactions. Additionally, the proposed model is capable to effectively capture the time scale pertinent in the wettability alteration by LSWF via reaction rate and near solid surface diffusion coefficients. The model is developed and incorporated into OpenFOAM and both the Navier-Stokes equation for oil/water two-phase flow and the advection-diffusion equation for ion transport are solved. The developed model is validated against one dimensional (1D) sinusoidal micromodel experiments reported in the literature, and then applied to two dimensional (2D) heterogeneous micromodel to investigate the sole effect of wettability alteration as well as its coupled effect with IFT variations. Different degrees of contact angle alteration, different trends of IFT variations reported in the literature, as well as different injection scenarios (secondary or tertiary) are considered. 1D sinusoidal micromodel simulations visualize a dominant dynamic recovery mechanism which boosts the low salinity effect (LSE) via coalescence of the detached or partially detached residual oil blobs which forms a large oil ganglion towards the downstream and can effectively produce the residual oil saturation at shorter period of time compared to the case if such a coalescence didn't happen. The sensitivity analysis in 2D heterogeneous micromodel shows that the performance of the LSWF is a function of the degree of wettability alteration as well as IFT variations. Although the IFT decreasing trend with salinity can enhance the oil production through synergetic effect, the IFT increasing trend has a detrimental effect on the oil production and surpasses the effectiveness of wettability alteration interactions. The results confirm the importance of fluid/fluid interactions such as IFT variation on the LSE which has been previously ignored in numerical simulation LSWF altogether. The presented simulations shed the lights to the reasons behinds some of the discrepancies reported in the literature.

Experimental Investigation of the Role of DC Voltage in the Wettability Alteration in Tight Sandstones.

The usage of direct current (DC) voltage has enormous potential for oil fields due to the effect of wettability alteration. However, the unclear mechanism of the wettability alteration has limited the application of this technology to oil fields. In this study, chemical and physical methods including contact angle tests, Fourier-transform infrared spectroscopy (FTIR) measurements, and atomic force microscope (AFM) experiments were combined to investigate the wettability alteration mechanism for tight sandstones subjected to DC voltage treatment. From the view of a chemical factor, FTIR results show that DC voltage decreases the number of Si-O-Si, C-O-C, C-O, and COOH groups, while it also increases the number of C═O and OH groups. The changes in molecular groups further improve the water-wetting property of tight sandstones. On the other hand, in a physical way, AFM results indicate that DC voltage improves the roughness of the rock surface. At the same time, the wetting state transfers from the Cassie-Baxter to the Wenzel. This increases the contact area of the solid-liquid interface. The augment of roughness and the transfer of the wetting state improve the water-wetting property of tight sandstones. By comparing the influences of both chemical and physical factors on wettability, it is concluded that although roughness indeed affects the wettability, chemical factors play a dominant role in determining the wettability. Achievements in this study can help researchers and engineers better understand the mechanism of wettability alteration and further accelerate the development of tight sandstones with DC voltage-related technology.

Direct numerical simulation of the effects of fluid/fluid and fluid/rock interactions on the oil displacement by low salinity and high salinity water: Pore-scale occupancy and displacement mechanisms

Laboratory experiments have shown that performance of waterflooding in oil reservoirs could be significantly increased by lowering the ionic strength and/or manipulation of its composition, which is generally known as low salinity waterflooding (LSWF). The involved mechanisms in additional oil production can be generally categorized in two categories, fluid/fluid and fluid/rock interactions. The distribution of the phases and the involved displacement mechanisms would be strongly affected by the inter-relations between capillary and viscous forces. Although there have been recent advances in the simulation of the LSWF at core scale and beyond and some models are included in commercial core-scale/field-scale simulators, there are very few works that modelled and simulated this process at the pore scale. As a result the effects of wettability alteration and/or interfacial tension (IFT) change on the distribution of the phases at pore scale as well as dynamics of the displacement are not thoroughly investigated and not well understood, even in spite of many micromodel experiments. The aim of the present study is to investigate the fluids distribution, redistribution and dynamic of the displacement mechanisms at the true pore scale (inside a pore), by modelling both rock/fluid (dynamic contact angle) and fluid/fluid (dynamic oil/water IFT as well as diffusion between high salinity and low salinity water) interactions. Simulation results show that in addition to the fluid/rock interactions, fluid/fluid interactions are also important in the effectiveness of LSWF and shall be considered in simulation studies. This is especially true in the case of non-water-wet systems. Our simulations provide new physical insights into LSWF and the dynamics of two-phase flow under wettability alteration as well as IFT changes induced by the LSWF, which cannot be easily captured by laboratory experiments. The results are also used to better explain some of the observed discrepancies in larger scales such as micromodel or coreflood experiments.

Interfacial Phenomena Effect on Sand Production Due to Optimized Smart Water with/without the Presence of Nanoparticles

Historically, smart water flooding is proved as one of the methods used to enhance oil recovery from hydrocarbon reservoirs. This method has been spread due to its low cost and ease of operation, with changing the composition and concentration of salts in the water, the smart water injection leads to more excellent compatibility with rock and fluids. However, due to a large number of sandstone reservoirs in the world and the increase of the recovery factor using this high-efficiency method, a problem occurs with the continued injection of smart water into these reservoirs a phenomenon happened in which called rock leaching. Indeed, sand production is the most common problem in these fields. Rock wettability alteration toward water wetting is considered as the main cause of sand production during the smart water injection mechanism. During this process, due to stresses on the rock surface as well as disturbance of equilibrium, the sand production in the porous media takes place. In this paper, the effect of wettability alteration of oil wetted sandstones (0.005,0.01,0.02 and 0.03 molar stearic acid in normal heptane) on sand production in the presence of smart water is fully investigated. The implementation of an effective chemical method, which is nanoparticles, have been executed to prevent sand production. By stabilizing silica nanoparticles (SiO2) at an optimum concentration of 2000 ppm in smart water (pH=8) according to the results of Zeta potential and DLS test, the effect of wettability alteration of oil wetted sandstones on sand production in the presence of smart water with nanoparticles is thoroughly reviewed. Ultimately, a comparison of the results showed that nanoparticles significantly reduced sand production.

Sandstone Reservoir Wettability Alteration Due to Water Softening: Impact of Silica Nanoparticles on Sand Production Mechanism

Low salinity water in the oil reservoirs changes the wettability and increases the oil recovery factor. In sandstone reservoirs, the sand production occurs or intensifies with wettability alteration due to low salinity water injection. In any case, sand production should be stopped and there are many ways to prevent sand production. By modifying the composition of low salinity water, it can be adapted to be more compatible with the reservoir rock and formation water, which has the least formation damage. By eliminating magnesium and calcium ions, smart soft water (SSW) is created which is economically suitable for injection into the reservoirs. By stabilizing the nanoparticles in SSW, nanofluids can be prepared which with injection into the sandstones reservoir increase the oil recovery, change the wettability and increase the rock strength. In this present, SSW composition was determined by compatibility testing, and the SiO2 nanoparticle with 1000 ppm concentration was stabilized in SSW. Eight thin sections were oil wetted by using normal heptane solution and different molars of stearic acid and two thin sections were considered as base thin sections to compare the effect of wettability alteration on sand production. Thin sections were immersed in SSW and Nanofluid, the amount of contact angle and sand production were measured in both cases. The amount of sand produced and the contact angle in SSW was higher than the Nanofluid. The silica nanoparticles reduced the contact angle (more water wetting) and by sitting between the sand particles, more than 40%, it reduced sand production.

Impact of pore morphology on two-phase flow dynamics under wettability alteration

Low salinity waterflooding aims to alter rock wettability from oil-wet towards less oil-wet or water-wet conditions. There is a limited understanding of how wettability alteration impacts two-phase flow, which is why it is unclear how wettability change impacts oil recovery. This study is an attempt to evaluate the effect of wettability alteration on two-phase flow for different pore size distributions under tertiary mode of low salinity waterflooding. Pore-scale, two-phase flow simulations with wettability alteration were performed in OpenFOAM’s CFD tool. Two synthetic pore geometries (domains) were constructed with identical pore topology and connectivity, but different variances of pore throat radii. In our simulations, the pore network with a larger variance in pore radii resulted in 12% additional oil recovery. Whereas, the network with smaller variance in pore radii experienced no additional oil recovery despite the same wettability alteration change. This implies that change of wettability in clusters with a larger variation of pore radii can lead to a larger variation in capillary pressure gradient due to wettability alteration, which induces remobilisation of the trapped oil.

Review of low salinity waterflooding mechanisms: Wettability alteration and its impact on oil recovery

Low salinity waterflooding (LSW) has attracted attention of numerous researchers as a promising technique for enhanced oil recovery, yet its application is still limited because of incomplete mechanisms and unreliable predictions. This paper summarizes relevant mechanisms for predicting responses of LSW. Since the wettability alteration is generally regarded as the most important one among possible LSW mechanisms, two aspects of predicting LSW responses are reviewed: prediction of wettability alteration and effects of wettability alteration on oil recovery. For the first aspect, the importance of more quantitative prediction of wettability alteration is addressed because experimental results have suggested that the optimal wettability may not be water-wet as imagined. From the relation between wettability and interaction forces in the oil-brine-rock systems, mechanisms of wettability alteration are reviewed along with quantitative calculation. The extended Derjaguin-Landau-Verwey-Overbeek (DLVO) theory, which has been often used to calculate the contact angles, is not available to obtain an accurate contact angle anymore. For the second aspect, an overview of the optimal wettability for oil recovery is given with relevant pore-scale fluid mechanisms. Though experiments found the maximum oil recovery from weakly water-wet or neutral wet rocks, the results were not elaborate enough to reveal the relation between the contact angle and the oil recovery. The pore-scale simulation is a powerful tool to investigate such relations but so far it still needs further developments on scaling and validations with experimental data.