Description:FIELD OF THE INVENTION:
The present invention belongs to enhanced oil recovery (EOR) techniques and particularly relates to the development of stable nanofluid formulations incorporating hydrophilic silica nanoparticles (SiO2), anionic and non-ionic surfactants, and polymers for improving residual oil recovery in sandstone reservoirs.
BACKGROUND OF THE INVENTION:
Enhanced oil recovery (EOR) techniques have gained significant attention in recent years as global energy demands continue to rise. The depletion of conventional oil reserves has driven the exploration of innovative methods to extract residual oil trapped in reservoirs. Among these methods, chemical and nanotechnology-based approaches have emerged as promising solutions to improve recovery efficiency and maximize resource utilization. Nanotechnology offers unique advantages in EOR, including the ability to alter interfacial properties, enhance fluid stability, and improve reservoir sweep efficiency. Hydrophilic nanoparticles, when used in conjunction with surfactants and polymers, have shown potential to modify wettability and reduce interfacial tension, two critical factors for effective oil recovery. These advancements align with the broader goal of sustainable and efficient resource extraction, ensuring the optimal utilization of hydrocarbon reservoirs.
CN116285926A discloses a composite nanofluid oil displacement agent resistant to high calcium and magnesium ions and a batch preparation method of the composite nanofluid oil displacement agent.
US202117381344A discloses an Enhanced oil recovery (EOR) including with a lamellar phase having Janus nanoparticles, petroleum surfactant, crude oil, and water and with additional water to give the flooding fluid that may be pumped through a wellbore into a subterranean formation to affect a property of hydrocarbon in the subterranean formation via contact of the flooding fluid with the hydrocarbon.
CN103937478A discloses a preparation method of a nanofluid for improving oil recovery. Involves surfactant and the PEG, mechanically stirring for 6-8 hours, washing the stirred dispersion 2-3 times, adjusting the pH value to the range of 8-9, and adding deionized water to 1L, thereby obtaining the water-based nanofluid.
The prior arts represent a significant step forward in addressing challenges associated with heavy crude oil reservoirs and improving recovery outcomes. However, there exists a need for the comparative efficacy of chemical and nanofluid-based EOR techniques, emphasizing the potential of nanofluids to transform the field of oil recovery.

OBJECTS OF THE INVENTION

One or more of the problems of the conventional prior art may be overcome by various embodiments of the system and methods of the present invention.

The principal object of the present invention is to enhance residual oil recovery (EOR) in sandstone reservoirs through the application of nanofluid flooding techniques.

One another object of the present invention is to develop stable nanofluid formulations incorporating hydrophilic silica nanoparticles (SiO2), surfactants, and polyacrylamide (PAM) polymers.

Another object of the present invention is to achieve wettability alteration through structural disjoining pressure for improved oil displacement efficiency.

A further object of the present invention is to reduce interfacial tension (IFT) at the oil-water interface using an optimized chemical and nanoparticle combination.

Yet another object of the present invention is to minimize emulsion creaming and improve nano-emulsion stability for enhanced reservoir sweep efficiency.

A still further object of the present invention is to provide an enhanced oil recovery solution with high cumulative oil recovery rates using nanofluid systems.

An additional object of the present invention is to mitigate sedimentation and agglomeration in nanofluid solutions, ensuring colloidal stability and uniform dispersion.
Another object of the present invention is to optimize the use of anionic surfactants like sodium dodecyl sulfate (SDS) and alpha-olefin sulfonate (AOS) for environmental sustainability in EOR applications.

Another object of the present invention is to enhance pressure drop and form an oil bank during nanofluid flooding, facilitating higher crude oil recovery.

Another object of the present invention is to demonstrate superior performance over conventional chemical flooding techniques in heavy crude oil reservoirs.

Other objects and advantages of the present disclosure will be more apparent from the following description, which is not intended to limit the scope of the present disclosure.

SUMMARY OF THE INVENTION

Thus, according to the basic aspect of the present invention, there is a nanofluid for enhanced oil recovery, obtained by a process comprising:
preparing a polymer solution by dissolving 2000 ppm of polyacrylamide (PAM) in deionized water under continuous stirring for approximately 12 hours;
adding a surfactant selected from sodium dodecyl sulfate (SDS), alpha-olefin sulfonate (AOS), Tergitol, or TX-100 to the polymer solution in a concentration based on the critical micelle concentration (CMC) values of the respective surfactants, forming a surfactant-polymer solution;
introducing 0.3 wt% hydrophilic silica nanoparticles (SiO2) to the surfactant-polymer solution; and
sonicating the mixture for 1 hour to obtain a stable nanofluid.

Another aspect of the present invention wherein the polymer solution is formed by adding PAM to deionized water in several steps to ensure homogeneity, followed by overnight stirring. The process involves gradual addition prevents local oversaturation, ensuring complete hydration and dissolution. The extended stirring period (approximately 12 hours) ensures a uniform polymer solution, critical for subsequent interactions with surfactants and nanoparticles. This step guarantees the stability and functionality of the final nanofluid.

Another aspect of the present invention, wherein the surfactant-polymer solution is prepared using a surfactant concentration specific to the following:
0.231 wt% for SDS,
0.1 wt% for AOS,
0.006 wt% for Tergitol, and
0.02 wt% for TX-100.
Each surfactant's concentration is tailored to its CMC value to maximize its effectiveness without causing excessive foaming or surfactant waste. Said surfactants play a critical role in improving the wettability and oil displacement efficiency of the nanofluid.

Another aspect of the present invention, wherein the hydrophilic silica nanoparticles are uniformly dispersed to achieve a zeta potential of = -30 mV, ensuring colloidal stability. Such a zeta potential value ensures strong electrostatic repulsion between nanoparticles, preventing aggregation or sedimentation. The observed stability is essential for maintaining the efficacy of the nanofluid over extended periods, especially under reservoir conditions.

Another aspect of the present invention, wherein the process achieves a nano-emulsion with a stability of up to 4 days, reducing creaming and improving reservoir sweep efficiency. The inclusion of nanoparticles and surfactants ensures a stable emulsion that resists phase separation (creaming) for up to 4 days. Said prolonged stability enhances the ability of nanofluid to displace oil uniformly across the reservoir, increasing the overall sweep efficiency.

Another aspect of the present invention, wherein the nanofluid reduces interfacial tension at the oil-water interface through effective packing of surfactants and nanoparticles. The combined effect of surfactants and nanoparticles ensures efficient packing at the oil-water interface, weakening the cohesive forces within the oil phase. The observed reduction in interfacial tension facilitates the mobilization of trapped oil droplets, leading to improved oil recovery.

Another aspect of the present invention, wherein the process results in wettability alteration of the reservoir surface due to structural disjoining pressure, enhancing oil displacement. The presence of nanoparticles induces structural disjoining pressure, altering the reservoir rock wettability from oil-wet to water-wet. The observed alteration reduces the adhesion of oil to the rock surface, improving the ease of oil displacement and recovery.

Another aspect of the present invention, wherein the preparation process facilitates higher pressure drops during flooding, indicating the formation of an oil bank and higher oil recovery efficiency. The higher pressure drops observed during the injection of the nanofluid indicate the formation of an oil bank, a collection of mobilized oil ahead of the advancing fluid front.

BRIEF DESCRIPTION OF THE DRAWINGS

Figure 1 illustrate results obtained in a stability analysis by visual observation at 30oC highlighting the sedimentation behavior of different nanofluid samples up to different time intervals, according to the present invention.
Figure 2 illustrates a reduction in interfacial tension between oil-water interface using different surfactants and surfactant-polymer combinations, according to the present invention.
Figure 3 illustrates an emulsion and nano-emulsion behavior to predict emulsion stability a) Creaming index and b) Microscopic image of nano-emulsion indicating packing of particles on droplet surface, according to the present invention.
Figure 4 illustrates results from contact angle measurements with different chemical and nanofluid combinations, according to the present invention.
Figure 5 shows core flooding data highlighting a) cumulative oil recovery for chemical and nanofluid flooding and b) residual oil recovery along with its corresponding highest pressure drop detected, according to the present invention.

DETAILED DESCRIPTION OF THE INVENTION WITH REFERENCE TO THE ACCOMPANYING FIGURES

The present invention as herein provided a nanofluid for enhanced oil recovery, obtained by a process comprising, preparing a polymer solution by dissolving 2000 ppm of polyacrylamide (PAM) in deionized water under continuous stirring for approximately 12 hours, adding a surfactant selected from sodium dodecyl sulfate (SDS), alpha-olefin sulfonate (AOS), Tergitol, or TX-100 to the polymer solution in a concentration based on the critical micelle concentration (CMC) values of the respective surfactants, forming a surfactant-polymer solution, introducing 0.3 wt% hydrophilic silica nanoparticles (SiO2) to the surfactant-polymer solution, and sonicating the mixture for 1 hour to obtain a stable nanofluid.

The stability of the nanoparticles suspended in nanofluid solutions were observed by sedimentation behavior visually and zeta potential analysis. The nanofluid samples was kept in the transparent glass test tube in an undisturbed condition for several days and accordingly the sedimentation was visualized. The nanofluid samples were further exposed to zeta potential analysis to further confirm the agglomerations behavior of the suspended nanoparticles with respect to time. The interfacial tension between crude oil and surfactant solutions were measured using the spinning drop tensiometer. The emulsification studies for each surfactant-polymer combinations were executed by mixing the samples with heavy crude oil in the ratio of 1:1. The concentration of surfactants were selected closed to its critical micelle concentration (CMC) values (AOS – 0.1 wt%, SDS – 0.231 wt%, TX-100 – 0.02 wt% and Tergitol – 0.06 wt%) and polymer (PAM) at fixed concentration of 2000 ppm. The surfactant-polymer solutions were first in a transparent vial, and to which crude oil was poured from top and mixed rigorously at 50 RPM in Tarson rotaspin (3090X). The wettability alteration experiments were performed by measuring the contact angle established between reservoir rock, crude oil and chemical/nanofluid solutions. The angle of contact was measure in drop shape analyzer.

Referring to Figure 1, in an aspect, the stability of suspended nanoparticles in base fluid such as deionized water, polymer and surfactant-polymer solutions illustrated. The nanoparticles were perfectly stable in chemical (polymer/surfactant-polymer) phase even after 15 days. This stability was due to the synergistic interaction between chemical and nanoparticles which does not allow then to aggregate and settle at the bottom indicating minimum or negligible sedimentation. However, with deionized water as base fluid, the nanoparticles were not stable even up to 24 hrs and this was due to the electrostatic interaction between the nanoparticles which promotes the sedimentation and thereby undergoes extreme agglomerations. Thus, the stability of nanoparticles is dependent on the viscosity of base fluid, electrostatic interaction (attraction and repulsive forces) and Brownian motion of the nanoparticles. The negligible sedimentation behavior was further confirmed by analyzing the zeta value of the nanofluid samples as shown in table 2. The zeta potential of the nanofluid sample retaining surfactant SDS was found to be -68.6 mV which reduces to -65.0 mV and -57.1 mV on 7th and 15th day respectively. Similar reduction in zeta value behavior was observed for other nanofluid solutions (NSP 2 to NSP 4). However, all the samples showed zeta value = -30 mV which clearly indicates the stability of all the nanofluid samples with time up to 15 days.
Table 1: Zeta potential values of nanofluid samples at 30oC and time interval up to 15 days.
Sample Zeta potential (mV)
Day 1 Day 7 Day 15
NSP 1 -68.6 -65.0 -60.1
NSP 2 -66.3 -57.1 -50.4
NSP 3 -45.1 -38.3 -36.9
NSP 3 -57.6 -47.1 -43.6

Referring to Figure 2, in an aspect, the efficiency of different surfactant-polymer (chemical) combinations to lower the interfacial tension is illustrated. The interfacial tension of the crude oil with deionized water was found to be around 18.4 mN/m which reduces to 0.55 mN/m, 0.32 mN/m, 0.64 mN/m and 0.12 mN/m for SDS, AOS, Tergitol and TX-100 respectively. The reduction in IFT with surfactant was due to the accumulation of surfactant molecules at the oil water interface which reduces the dissimilarities at interface and thereby reduces the IFT. The lowest IFT with TX-100 was observed due to the improved interaction (hydrophilic head with water and hydrophobic tail group interaction with oil) with respect to remaining three surfactants. Thus, depending on such interactions, the reduction in IFT for all the chosen surfactants followed the order as TX-100> AOS > SDS > Tergitol. The IFT reduction is one of the most important factors which governs the residual oil recovery factor. This is because of the enhancement in capillary number which releases the trapped residual oil from the pores of the reservoir rock. However, there are several other factors which controls the IFT reduction as surfactant type, surfactant molecular structure, number of carbon atom in surfactant, oil type, oil properties (SARA), HLB, interfacial interaction, salt, temperature, in-situ soap/surfactant, position of surfactant at interface, packing of surfactant, micelle types and many more. Similarly for SP 1, SP 2, SP 3 and SP 4, the IFT detected were 0.48 mN/m, 0.24 mN/m, 0.62 mN/m and 0.10 mN/m respectively. The data showed that the presence of polymer in surfactant solutions have no or negligible impact on IFT reduction. However, it enhances the time required to reach the equilibrium IFT which could be due to slower rate of diffusion of surfactant molecule at the interface in presence of polymer. The IFT is expected to reduce further when nanoparticles are added to the surfactant-polymer solutions (nanofluid - NSP 1, NSP 2, NSP 3 and NSP 4).
Referring to Figure 3a, in an aspect, the creaming behavior of emulsion and nano-emulsion with respect to time (in days) is illustrated. The creaming index started at zero from the beginning of emulsion formation (stable emulsion) and then increases with time (destabilizing emulsion). The emulsion forms by chemical combinations (SP 1, SP 2, SP 3 and SP 4) showed higher creaming, as compared to nano emulsion formed using nanofluid (NSP 1, NSP 2, NSP 3 and NSP 4) with lower. Said activity resulted in higher creaming index value for SP systems as compared to NSP systems. The creaming index after 24 hrs was more than 90% for Tergitol (SP 3) and close to 90% for TX-100 (SP 4). When nanoparticles were incorporated the creaming index reduces to almost 80% for Tergitol (NSP3) and approximately 60% for TX-100 (NSP 4). For SDS (SP 1) and AOS (SP 2), the creaming index after 24 hours was lower and found to be around 70% and 60% respectively. The same system with nanoparticles showed creaming index of almost <15% and <10% respectively after 24 hrs. The creaming index variation were almost negligible after 24 hrs. The higher creaming is governed by the electrostatic interaction between the emulsion droplets. The packing of surfactant and polymer at the oil-water interfaces showed electrostatic repulsive forces which induces stable emulsion. However, with nanoparticles the packing is more effective at the oil-water interface. This results in the further improvement of repulsive forces between the emulsion droplets and thereby results in stable emulsion with lesser serum height signifying lower creaming index.

Referring to Figure 3b, in an aspect, the stability of nano-emulsion was further analyzed by microscopic image of emulsion produced by NSP 1 is illustrated. The image clearly indicates the presence of nanoparticles at the outer surface of emulsion droplets. These nanoparticles are responsible for producing stronger electrostatic repulsion forces which does not allows the droplets to coagulate easily, and thus more stable emulsion was observed in presence of nanoparticles (stable nano-emulsion).

Referring to Figure 4, in an aspect, the impact of different chemical and nanofluid combinations on change in contact angle is illustrated. The contact angle obtained using deionized water was 68° revealing the reservoir to be intermediate wet. With chemical solutions, the contact angle was further reduced to 26°, 25°, 33° and 24° using SP 1, SP 2, SP 3 and SP 4 respectively. The lowest contact angle of 14°, 13°, 20° and 12° was measured with nanoparticles using NSP 1, NSP 2, NSP 3 and NSP 4 respectively.
The drastic change in contact angle with different chemical and nanofluid combinations highlighted the change in wettability of the reservoir rock from intermediate wet to desirable water wet. The change in wettability with surfactants results due to the hydrogen bonding, and interaction of hydrophilic and hydrophobic groups at the oil-water-rock contact point. The adsorption of surfactant molecules from different categories on the oil saturated rock surfaces, mechanism of ion-pair formation and ion exchange are responsible for the wettability alteration. The wettability alteration with nanofluid solutions were due to the formation structural disjoining pressure at the oil-water-rock contact point. The nanoparticles in nanofluid solutions induces greater electrostatic repulsion forces and due to its Brownian motion, when comes into contact at the oil-water-rock surface produces a wedge film leading to structural disjoining pressure.

Referring to Figure 5a, in an aspect, the oil recovery obtained by chemical and nanofluid solutions were estimated by core flooding experiments illustrated. The secondary water flooding oil recovery was in the range of 34.7 – 36.7% IOIP using 2 PV of water flooding.

Referring to Figure 5b, in an aspect, after water flooding, a chemical/nanofluid slug of 0.5 PV was then injected followed by 1.5 PV chase water flooding illustrated. The residual oil recovery with SP 1, SP 2, SP 3 and SP 4 was found to be 21.5, 25.6, 17.2 and 18.6% IOIP respectively. For the same system when nanoparticles are applied, the residual oil recovery was enhanced to 28.6% for NSP 1, 33.4% for NSP 2, 19.6% for NSP 3 and 22.8% for NSP 4.

The increment in oil recovery with nanoparticles was due to the stability in nano-emulsion as observed by creaming behavior. The stable suspended nanoparticles in the nano-emulsion reduces the droplets coalescence due to the electrostatic repulsion resulting in lower creaming rate. Moreover, additionally wettability alteration in reservoir due to structural disjoining pressure further enhances the oil displacement efficiency which therefore induces the maximum oil recovery. A highest pressure drop (~ 95 Psi) was obtained with nanofluid solutions (NSP 2) during the core flooding as shown in figure 8b. This indicates the formation of additional/greater quantity of oil bank and thus results in higher oil recovery. The recovery was higher for remaining nanofluid solutions in the order of NSP 1 > NSP 4 > NSP 3 which is a direct function of pressure drop. The other possible reason for higher pressure drop could be due to the enhancement in viscosity of nanofluid solutions. The pressure drop may also result due to the blockage of pores during nanofluid flooding and such studies can be considered in future investigations. Thus, the present invention concludes that nano-emulsion was found to be better in terms of oil recovery as compared to emulsion.

TECHNICAL ADVANCEMENTS OF THE PRESENT INVENTION

The invention presented the efficacy of chemical vs nanofluid flooding in terms of residual oil recovery for sandstone reservoir. The impact of hydrophilic nanoparticles and its interaction with different anionic and non-ionic in presence of polymer were investigated for heavy crude oil reservoirs. The overall major technical advancements derived from the present invention has been formulated as follows:
The nanofluid system achieves superior colloidal stability with a zeta potential of = -30 mV, preventing nanoparticle aggregation.

Nano-emulsions formed with silica nanoparticles remain stable for up to 4 days, significantly outperforming conventional surfactant-based emulsions.

The nanofluid reduces interfacial tension at the oil-water interface, enhancing oil displacement efficiency.

Structural disjoining pressure induced by the nanofluid effectively alters reservoir rock wettability from oil-wet to water-wet.

The nanofluid flooding process results in higher pressure drops, indicating the formation of an oil bank for improved recovery.

Cumulative oil recovery of up to 68.1% is achieved, surpassing traditional chemical flooding methods.

The nanofluid system reduces creaming by at least 50%, ensuring better reservoir sweep efficiency.

Anionic surfactants optimized for the nanofluid system provide cost-effective solutions for enhanced oil recovery.

The process ensures uniform dispersion of silica nanoparticles, enhancing stability and performance under reservoir conditions.

The integration of surfactants, polymers, and nanoparticles in a single nanofluid formulation addresses multiple EOR challenges simultaneously.

The embodiments herein and the various features and advantageous details thereof are explained with reference to the non-limiting embodiments in the following description. Descriptions of well-known components and processing techniques are omitted to not unnecessarily obscure the embodiments herein. The examples used herein are intended merely to facilitate an understanding of ways in which the embodiments herein may be practiced and to further enable those of skill in the art to practice the embodiments herein. Accordingly, the examples should not be construed as limiting the scope of the embodiments herein. While considerable emphasis has been placed herein on the components and component parts of the preferred embodiments, it will be appreciated that many embodiments can be made and that many changes can be made in the preferred embodiments without departing from the principles of the disclosure. These and other changes in the preferred embodiment as well as other embodiments of the disclosure will be apparent to those skilled in the art from the disclosure herein, whereby it is to be distinctly understood that the foregoing descriptive matter is to be interpreted merely as illustrative of the disclosure and not as a limitation.
, Claims:1. A nanofluid for enhanced oil recovery, obtained by a process comprising:
preparing a polymer solution by dissolving 2000 ppm of polyacrylamide (PAM) in deionized water under continuous stirring for approximately 12 hours;
adding a surfactant selected from sodium dodecyl sulfate (SDS), alpha-olefin sulfonate (AOS), Tergitol, or TX-100 to the polymer solution in a concentration based on the critical micelle concentration (CMC) values of the respective surfactants, forming a surfactant-polymer solution;
introducing 0.3 wt% hydrophilic silica nanoparticles (SiO2) to the surfactant-polymer solution; and
sonicating the mixture for 1 hour to obtain a stable nanofluid.

2. The nanofluid as claimed in claim 1, wherein the polymer solution is formed by adding PAM to deionized water in several steps to ensure homogeneity, followed by overnight stirring.

3. The nanofluid as claimed in claim 1, wherein the surfactant-polymer solution is prepared using a surfactant concentration specific to the following:
0.231 wt% for SDS,
0.1 wt% for AOS,
0.006 wt% for Tergitol, and
0.02 wt% for TX-100.

4. The nanofluid as claimed in claim 1, wherein the hydrophilic silica nanoparticles are uniformly dispersed to achieve a zeta potential of = -30 mV, ensuring colloidal stability.

5. The nanofluid as claimed in claim 1, wherein the process achieves a nano-emulsion with a stability of up to 4 days, reducing creaming by at least 50% compared to chemical solutions and improving reservoir sweep efficiency by achieving an incremental oil recovery of 10%–15%.

6. The nanofluid as claimed in claim 1, wherein the nanofluid reduces interfacial tension at the oil-water interface through effective packing of surfactants and nanoparticles.

7. The nanofluid as claimed in claim 1, wherein the process results in wettability alteration of the reservoir surface due to structural disjoining pressure, enhancing oil displacement.

8. The nanofluid as claimed in claim 1, wherein the preparation process facilitates higher pressure drops of up to 25% during flooding, indicating the formation of an oil bank and achieving a cumulative oil recovery rate of 68.1%.