scholarly journals Review on enhanced oil recovery by nanofluids

2018 ◽  
Vol 73 ◽  
pp. 37 ◽  
Author(s):  
Kewen Li ◽  
Dan Wang ◽  
Shanshan Jiang
Keyword(s):  
Experimental Data ◽  
Aqueous Solution ◽  
Surface Tension ◽  
Oil Recovery ◽  
Wettability Alteration ◽  
Oil Viscosity ◽  
Interfacial Surface ◽  
Lack Of Control ◽  
Water Based ◽  
Enhance Oil Recovery

The addition of nanoparticles into water based fluids (nanofluid) with or without other chemicals to Enhance Oil Recovery (EOR) has recently received intensive interest. Many papers have been published in this area and several EOR mechanisms have been proposed. The main EOR mechanisms include wettability alteration, reduction in InterFacial surface Tension (IFT), increase in the viscosity of aqueous solution, decrease in oil viscosity, and log-jamming. Some of these mechanisms may be associated with the change in disjoining pressure because of the addition of the nanoparticles. The experimental data and results reported by different researchers, however, are not all consistent and some even conflict with others. Many papers published in recent years have been reviewed and the associated experimental data have been analyzed in this paper in order to clarify the mechanisms of EOR by nanofluids. Wettability alteration may be one of the most accepted mechanisms for nanofluid EOR while reduction in IFT and other mechanisms have not been fully proven. The main reason for the inconsistency among the experimental data might be lack of control experiments in which the effect of nanoparticles on oil recovery would be singled out.

Implications of Shale Oil Compositions on Surfactant Efficacy for Wettability Alteration

2015 ◽  
Author(s):  
Lijie Feng ◽  
Xu Liang
Keyword(s):  
Surface Tension ◽  
Cationic Surfactant ◽  
Oil Recovery ◽  
Anionic Surfactant ◽  
Ion Pairs ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Base Number ◽  
Shale Oil ◽  
Interfacial Surface

Abstract Surfactant selection is important for oil recovery in a hydraulically fractured reservoir. Two primary mechanisms, ion-pair coupling (cleaning) between surfactant and hydrocarbon and surfactant adsorption onto the rock surface (coating), were previously suggested to explain how surfactants can alter rock wettability, thus improving oil production. Because of the electrostatic interaction, acidic compounds in the oil tend to be adsorbed onto rock surface that is positively charged; whereas basic compounds are preferentially attracted to rock surface that is negatively charged. It has been discussed in previous literature that for wettability alteration for conventional formation rocks, the cleaning mechanism could be more efficient by inducing ion pairs between surfactants and oil compounds that have opposite charges, rather than the coating mechanism that mainly relies on how well surfactant covers the rock surface. In this research, 90 shale oils from various liquids shale plays, such as the Eagle Ford and the Wolfcamp, were tested for total acid number (TAN) and total base number (TBN). Cationic and anionic surfactants with low interfacial surface tension, along with Berea sandstone and Indiana limestone, were used to investigate the extent that TAN and TBN can be used as criteria to select surfactants. Oil recovery, imbibition, interfacial surface tension, and emulsion tendency were conducted to examine whether the cleaning mechanism holds true for shale oil saturated formation rocks. The results demonstrated that for carbonates with shale oil having a higher TAN, a cationic surfactant provided the potential to sweep more oil than an anionic surfactant. On the other hand, for sandstone with shale oil having a higher TBN, an anionic surfactant performed better than a cationic surfactant. Those observations appear to be consistent with the proposed cleaning mechanism and resonate with production data for thousands of wells from some major liquids-rich shale plays.

A New Dynamic Wettability-Alteration Model for Oil-Wet Cores During Surfactant-Solution Imbibition

SPE Journal ◽  
2013 ◽  
Vol 18 (05) ◽  
pp. 818-828 ◽  
Author(s):  
M. Hosein Kalaei ◽  
Don W. Green ◽  
G. Paul Willhite
Keyword(s):  
Experimental Data ◽  
Oil Recovery ◽  
History Matching ◽  
Mechanistic Model ◽  
Surfactant Solution ◽  
Experimental Tests ◽  
Quantitative Agreement ◽  
Wettability Alteration ◽  
Porous Rock ◽  
Surfactant Solutions

Summary Wettability modification of solid rocks with surfactants is an important process and has the potential to recover oil from reservoirs. When wettability is altered by use of surfactant solutions, capillary pressure, relative permeabilities, and residual oil saturations change wherever the porous rock is contacted by the surfactant. In this study, a mechanistic model is described in which wettability alteration is simulated by a new empirical correlation of the contact angle with surfactant concentration developed from experimental data. This model was tested against results from experimental tests in which oil was displaced from oil-wet cores by imbibition of surfactant solutions. Quantitative agreement between the simulation results of oil displacement and experimental data from the literature was obtained. Simulation of the imbibition of surfactant solution in laboratory-scale cores with the new model demonstrated that wettability alteration is a dynamic process, which plays a significant role in history matching and prediction of oil recovery from oil-wet porous media. In these simulations, the gravity force was the primary cause of the surfactant-solution invasion of the core that changed the rock wettability toward a less oil-wet state.

scholarly journals Investigation on the effect of CuO nanoparticles on the IFT and wettability alteration at the presence of [C12mim][Cl] during enhanced oil recovery processes

2022 ◽  
Author(s):  
Nabeel Kadhim Abbood ◽  
Abdolrahman obeidavi ◽  
Seyednooroldin Hosseini
Keyword(s):  
Aqueous Solution ◽  
Oil Recovery ◽  
Considerable Effect ◽  
Cuo Nanoparticles ◽  
Wettability Alteration ◽  
Pendant Drop ◽  
Cuo Nps ◽  
Tertiary Oil Recovery ◽  
Wet Condition ◽  
Pendant Drop Method

AbstractIn the current study, the effect of CuO nanoparticles (CuO-NPs) at the presence of dodecyl-3-methylimidazolium chloride ([C12mim][Cl]) is investigated on the interfacial tension (IFT) reduction, wettability alteration, and even tertiary oil recovery. Since the prepared solutions with CuO-NPs are completely dark and it is impossible to measure the IFT of these solutions in the presence of crude oil using the pendant drop method (since one of the phases must be transparent for IFT measurement using the pendant drop method), n-heptane (representative of saturates) and toluene (representative of aromatics) are used only for IFT measurement of solutions prepared by CuO-NPs, while rest of the experiments are performed using crude oil. The obtained results reveal that CuO-NPs are not stable in the aqueous solution in the absence of surfactant which means fast precipitation of CuO-NPs and a high risk of pore plugging. In this way, the stability of CuO-NPs is investigated at the presence of dodecyl-3-methyl imidazolium chloride ([C12mim][Cl]) as an effective surfactant for stabilizing the CuO-NPs in the aqueous solution (more than 1 month without precipitation using 1000 ppm of IL). Further measurements reveal that although the presence of IL in the aqueous solution can reduce the IFT of oil/aqueous solution system, especially for the aqueous solutions prepared by formation brine (0.65 mN.m−1), the presence of CuO-NPs has no considerable effect on the IFT. On the other hand, not only the contact angle (CA) measurements reveal the considerable effect of IL on the wettability alteration toward water-wet condition (68.3° for IL concentration of 1000 ppm) but also the addition of CuO-NPs can significantly boost the wettability alteration toward strongly water-wet condition (23.4° for the concentration of 1000 ppm of CuO-NPs). Finally, several core flooding experiments are performed using different combinations of chemicals to find the effect of these chemicals on the tertiary oil recovery factor. The results reveal that the presence of CuO-NPs can enhance the oil recovery of injected chemical slug (aqueous solution prepared by dissolution of IL with an oil recovery factor of 10.1% based on Original oil in place (OOIP)) to 13.8, %, 16.9%, and 21.2% based on OOIP if 500, 1000, 2000 ppm of CuO-NPs existed in the solution concomitant with 1000 ppm of [C12mim][Cl].

Improvement of oil recovery factor from geological perspectives

2021 ◽  
pp. 17-25
Author(s):  
D.Yu. Chudinova ◽  
◽  
D.S. Urakov ◽  
Sh.Kh. Sultanov ◽  
Yu.A. Kotenev ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Late Stage ◽  
Field Data ◽  
Recovery Factor ◽  
Wettability Alteration ◽  
Stage Of Development ◽  
Number Of Factors ◽  
Enhance Oil Recovery ◽  
The Given ◽  
Selection Of

At a late stage of development of any oilfield, there are big number of factors that affect recovery factor. One of them is related to presence of isolated zones, that were caused by combination of poor reservoir and oil properties of a rock. To solve the given problem variety of workover operations and enhance oil recovery (EOR) methods can be appled for the complex reservoirs such as Tevlinsko-Russinskoe oilfield. The number of particular studies were presented by reviewing of field data, construction of heterogeneity zones, revision of workover operations and selection of EOR methods. It has obtained that the reservoir has the lenticular structure, consists from 9 different facies and presented by 4 classes of heterogeneity. The immiscible gas injections of Nitrogen were selected as the most suitable EOR method for the given oilfield. Application of different composition of brine water was reccomended for wettability alteration.

A Mechanistic Model for Wettability Alteration by Chemically Tuned Waterflooding in Carbonate Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (04) ◽  
pp. 767-783 ◽  
Author(s):  
C.. Qiao ◽  
L.. Li ◽  
R.T.. T. Johns ◽  
J.. Xu
Keyword(s):  
Experimental Data ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
Reactive Transport ◽  
Mechanistic Model ◽  
Contact Angles ◽  
Carbonate Reservoirs ◽  
Wettability Alteration ◽  
Physical Parameters ◽  
Minor Effect

Summary Injection of chemically tuned brines into carbonate reservoirs has been reported to enhance oil recovery by 5–30% original oil in place (OOIP) in coreflooding experiments and field tests. One proposed mechanism for this improved oil recovery (IOR) is wettability alteration of rock from oil-wet or mixed-wet to more-water-wet conditions. Modeling of wettability-alteration experiments, however, is challenging because of the complex interactions among ions in the brine and crude oil on the solid surface. In this research, we developed a multiphase and multicomponent reactive transport model that explicitly takes into account wettability alteration from these geochemical interactions in carbonate reservoirs. Published experimental data suggest that desorption of acidic-oil components from rock surfaces make carbonate rocks more water-wet. One widely accepted mechanism is that sulfate (SO42−) replaces the adsorbed carboxylic group from the rock surface, whereas cations (Ca2+, Mg2+) decrease the oil-surface potential. In the proposed mechanistic model, we used a reaction network that captures the competitive surface reactions among carboxylic groups, cations, and sulfate. These reactions control the wetting fractions and contact angles, which subsequently determine the capillary pressure, relative permeabilities, and residual oil saturations. The developed model was first tuned with experimental data from the Stevns Klint chalk and then used to predict oil recovery for additional untuned experiments under a variety of conditions where IOR increased by as much as 30% OOIP, depending on salinity and oil acidity. The numerical results showed that an increase in sulfate concentration can lead to an IOR of more than 40% OOIP, whereas cations such as Ca2+ have a relatively minor effect on recovery (approximately 5% OOIP). Physical parameters, including the total surface area of the rock and the diffusion coefficients, control the rate of recovery, but not the final oil recovery. The simulation results further demonstrate that the optimum brine formulations for chalk are those with relatively abundant SO42− (0.096 mol/kg water), moderate concentrations of cations, and low salinity (total ionic strength of less than 0.2 mol/kg water). These findings are consistent with the experimental data reported in the literature. The new model provides a powerful tool to predict the IOR potential of chemically tuned waterflooding in carbonate reservoirs under different scenarios. To the best of our knowledge, this is the first model that explicitly and mechanistically couples multiphase flow and multicomponent surface complexation with wettability alteration and oil recovery for carbonate rocks specifically.

Displacement Efficiency for Low-Salinity Polymer Flooding Including Wettability Alteration

SPE Journal ◽  
2016 ◽  
Vol 22 (02) ◽  
pp. 417-430 ◽  
Author(s):  
Saeid Khorsandi ◽  
Changhe Qiao ◽  
Russell T. Johns
Keyword(s):  
Experimental Data ◽  
Oil Recovery ◽  
Analytical Solutions ◽  
Polymer Concentration ◽  
Polymer Flooding ◽  
Wettability Alteration ◽  
Displacement Efficiency ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water

Summary Polymer flooding can significantly improve sweep and delay breakthrough of injected water, thereby increasing oil recovery. Polymer viscosity degrades in reservoirs with high-salinity brines, so it is advantageous to inject low-salinity water as a preflush. Low-salinity waterflooding (LSW) can also improve local-displacement efficiency by changing the wettability of the reservoir rock from oil-wet to more water-wet. The mechanism for wettability alteration for LSW in sandstones is not very well-understood; however, experiments and field studies strongly support that cation-exchange (CE) reactions are the key elements in wettability alteration. The complex coupled effects of CE reactions, polymer properties, and multiphase flow and transport have not been explained to date. This paper presents the first analytical solutions for the coupled synergistic behavior of LSW and polymer flooding considering CE reactions, wettability alteration, adsorption, inaccessible pore volume (IPV), and salinity effects on polymer viscosity. A mechanistic approach that includes the CE of Ca2+, Mg2+, and Na+ is used to model the wettability alteration. The aqueous phase viscosity is a function of polymer and salt concentrations. Then, the coupled multiphase-flow and reactive-transport model is decoupled into three simpler subproblems—the first in which CE reactions are solved, the second in which a variable polymer concentration can be added to the reaction path, and the third in which fractional flows can be mapped onto the fixed cation and polymer-concentration paths. The solutions are used to develop a front-tracking algorithm, which can solve the slug-injection problem of low-salinity water as a preflush followed by polymer. The results are verified with experimental data and PennSim (2013), a general-purpose compositional simulator. The analytical solutions show that decoupling allows for estimation of key modeling parameters from experimental data, without considering the chemical reactions. Recovery can be significantly enhanced by a low-salinity preflush before polymer injection. For the cases studied, the improved oil recovery (IOR) for a chemically tuned low-salinity polymer (LSP) flood can be as much as 10% original oil in place (OOIP) greater than with considering polymer alone. The results show the structure of the solutions, and, in particular, the velocity of multiple shocks that develop. These shocks can interact, changing recovery. For example, poor recoveries obtained in corefloods for small-slug sizes of low salinity are explained by the intersection of shocks without considering mixing. The solutions can also be used to benchmark numerical solutions and for experimental design. We demonstrate the potential of LSP flooding as a less-expensive and more-effective way for performing polymer flooding when the reservoir wettability can be altered with chemically tuned low-salinity brine.

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

Nanomaterials ◽  
2021 ◽  
Vol 11 (7) ◽  
pp. 1849
Author(s):  
Jinjian Hou ◽  
Lingyu Sun
Keyword(s):  
Synergistic Effect ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Interaction Force ◽  
Hot Water ◽  
Wettability Alteration ◽  
Heavy Oil Recovery ◽  
Optimal Salinity ◽  
Synergistic Mechanism ◽  
Enhance Oil Recovery

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.

scholarly journals Alteration wettability of carbonate rocks by Nano fluids and comparison with PEG and SDS

2020 ◽  
Vol 10 (4) ◽  
pp. 54-68
Author(s):  
Dr. Rana R Jalil ◽  
Dr. Hussein Qasim Hussein
Keyword(s):  
Oil Recovery ◽  
Carbonate Rocks ◽  
Saline Water ◽  
Sodium Dodecyl ◽  
Silica Nanoparticle ◽  
Wettability Alteration ◽  
Limestone Rock ◽  
The Stability ◽  
Enhance Oil Recovery ◽  
Sds Surfactant

This work was conducted to study limestone rock wettability alteration to enhance oil recovery by flooding using different Nano silica (NS) sizes suspended in saline water and compared with flooding solution of polyethylene glycol (PEG) polymer and sodium dodecyl sulfate (SDS) surfactant, the stability of nanofluids measured by zeta potential. In the flooding system, the secondary recovery by silica nanofluids (0.01 wt. % NS concentration) achieved an oil recovery of 35vol. % and 26.08 vol. % for 10, 52 nm after primary recovery respectively, while PEG polymer and SDS surfactant achieved oil recovery of 5 vol. % and 10 vol. % only respectively. The stability of pressure difference approved that silica nanoparticle never causes any plug or damage for the carbonate rocks

scholarly journals Study On Oil Reservoir Productivity Performance Via Combination of Taguchi and BEM Analyses

2007 ◽  
Vol 3 (1) ◽  
Author(s):  
Mohamad Nasir Mohamad Ibrahim ◽  
Solehuddin Shuib
Keyword(s):  
Oil Recovery ◽  
Influencing Factor ◽  
Reservoir Rock ◽  
Oil Reservoir ◽  
Oil Viscosity ◽  
Reservoir Performance ◽  
Recovery Techniques ◽  
Fluid Properties ◽  
The Right ◽  
Enhance Oil Recovery

The application of Taguchi Robust Design Technique (TRDT) coupled with the Boundary Element Method (BEM) in analyzing the productivity performance of an oil reservoir is presented in this paper. Several reservoir rock and reservoir fluid properties; i.e. permeability, thickness, porosity and viscosity, were chosen in this study. The BEM allows the overall simulation of reservoir performance to be made; whereas the used of TRDT allows us to rank the most influencing factor (property) that affects the productivity performance of the reservoir. Numerical values obtained from the BEM analysis will be used as input data for the TRDT statistical analysis. Results indicated that oil viscosity is the most important factor that affects the productivity performance of the oil reservoir followed by the thickness of the pay zone, the rock permeability and the rock porosity. Results of this study can be used by reservoir engineer in making the right choice of Enhance Oil Recovery techniques that is the most suitable for the reservoir.

scholarly journals Experimental study of microbial enhanced oil recovery in oil-wet fractured porous media

2020 ◽  
Vol 75 ◽  
pp. 73
Author(s):  
Amin Abolhasanzadeh ◽  
Ali Reza Khaz’ali ◽  
Rohallah Hashemi ◽  
Mohammadhadi Jazini
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Low Cost ◽  
Fractured Reservoirs ◽  
Gas Production ◽  
Wettability Alteration ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
The Matrix ◽  
Microbial Flooding

Without Enhanced Oil Recovery (EOR) operations, the final recovery factor of most hydrocarbon reservoirs would be limited. However, EOR can be an expensive task, especially for methods involving gas injection. On the other hand, aqueous injection in fractured reservoirs with small oil-wet or mixed-wet matrices will not be beneficial if the rock wettability is not changed effectively. In the current research, an unpracticed fabrication method was implemented to build natively oil-wet, fractured micromodels. Then, the efficiency of microbial flooding in the micromodels, as a low-cost EOR method, is investigated using a new-found bacteria, Bacillus persicus. Bacillus persicus improves the sweep efficiency via reduction of water/oil IFT and oil viscosity, in-situ gas production, and wettability alteration mechanisms. In our experiments, the microbial flooding technique extracted 65% of matrix oil, while no oil was produced from the matrix system by water or surfactant flooding.

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