Wettability Alteration Of Reservoir Rock Research Articles

Design and performance evaluation of Alkaline-Surfactant-Polymer slug of a natural surfactant of fenugreek in saline media for Foaming/Emulsification applications

The increasing demands of oil energy has created burden on conventional oil recovery methods because of which use of synthetic chemicals is increasing and creating significant health and environmental issues. Therefore, this study reports the synthesis of alkali-surfactant-polymer (ASP) slug with the use a natural surfactant and natural polymer as an alternate for foaming in saline environment of chemical-EOR applications. The natural surfactant (used at CMC level) derived from fenugreek seeds and guar gum (4000 ppm) was used as natural polymer, while the concentration of NaHCO3 (alkali) was tuned to curtail the impact of salt-ions on foam-ability of ASP slug for practical applications. It was observed that a stable air foam developed in saline medium due to the synergistic interaction between alkali-polymer. The desired ASP slug (nomenclature: 0.5ASP1) of 0.5 wt% alkali, 0.2 wt% surfactant (CMC), and 4000 ppm guar gum was developed after significant tuning in alkali concentration as per the variation in NaCl concentration (1–8 wt%). The desired slug 0.5ASP1 showed significant foaming potential till NaCl concentration of 2 wt% as demonstrated by superior foam height of 139.8 mm at span of 60 s which was only 113.4 mm for ASP slug (at salinity 2 wt%). The presence of alkali, capable of generating in-situ surfactant, and inclusion of additional natural surfactant in ASP formulation (0.5ASP1) resulted into minimum SFT of 38 mN/m and contact angle of 54°. This indicates a favorable impact of ASP slug on wettability alteration of reservoir rock and making them more water-wet. Microscopic investigations were also conducted to visualize packing and coverage of foam bubbles stabilized by 0.5ASP1 and ASP slugs. 0.5ASP1 slug sustained bubbles for longer duration than ASP slug. The results concluded that inclusion of natural derivative in form of surfactant and polymer along with inexpensive alkali makes ASP slug a green alternative for practical applications such as oil recovery, crude emulsification, CO2 foams, and IFT reduction.

Pore-Scale Investigation of Low-Salinity Nanofluids on Wetting Properties of Oil Carbonate Reservoir Rocks Studied by X-ray Micro-Tomography

Low-salinity surfactant nanofluids have recently shown promising results in the wettability alteration of reservoir rocks from oil-wet state towards more water-wet state. However, the investigation of pore-level interactions of nanofluids injection in real oil carbonate rocks at reservoir conditions, which determines the overall fluid dynamics, is lacking. Therefore, in this work, we studied the effect of nanoparticles augmented low-salinity surfactant flooding on the wettability alteration of hydrophobic carbonate rocks with harsh reservoir conditions via X-ray micro-tomography. The designed experiment scheme involved core flooding with an X-ray transparent core-holder developed for studying the flow properties of fluids at the micro level (pore scale). The wettability was quantified by measuring the differences in contact angles after the injection of low salinity, low-salinity surfactant, and low-salinity surfactant nanofluid. The findings illustrate that surfactant flooding with silica nanoparticles had a more pronounced influence on the contact angle among other injected fluids. The contact angle of the rock fell from 144° to 49°, corresponding to the water-wet conditions of carbonate rocks. The results show that the addition of a low concentration (0.005 wt.%) of SiO2 nanoparticles was enough for wettability changes in oil carbonate rocks. This study illustrates that a combination of surfactant, low-salinity, and nanoparticle features has a more pronounced effect on the three-phase contact angle than if applied separately.

Inhibition of asphaltene precipitation using hydrophobic deep eutectic solvents and ionic liquid

Precipitation and subsequent deposition of asphaltene in oil reservoirs may cause severe flow assurance problems due to clogging/blocking of pore spaces and wettability alteration of reservoir rocks towards oil-wetness. The present study focuses, for the first time, on the potential application of three hydrophobic deep eutectic solvents (HDESs) prepared by mixing methyltrioctylammonium chloride (N81Cl) as their hydrogen bond acceptor (HBA) with alcoholic hydrogen bond donors (HBDs), namely 1-propanol, 1,3-propanediol, and glycerol. The performance of HDESs was compared with a phosphonium-based hydrophobic ionic liquid (IL), Trihexyltetradecylphosphonium bis(2,4,4-trimethylpentyl)phosphinate (TTPBP), as well as dodecylbenzene sulfonic acid (DBSA), a conventional asphaltene precipitation inhibitor. Initially, the kinetic and onset of asphaltene precipitation were evaluated using an ultraviolet-visible (UV-Vis) spectrophotometer to determine the chemicals' inhibition propensity. Next, Fourier-transform infrared (FTIR) spectroscopy, thermogravimetric (TGA), and elemental analyses were used for the recovered asphaltenes from HDESs and TTPBP solutions to examine their structures. Spectrophotometry results revealed that glycerol-based HDES (HDES 3) and TTPBP could effectively inhibit the asphaltene precipitation, where their performances were comparable to that of DBSA. Besides, aromaticity index, thermal degradation, and H:C and oxygen contents provided evidence that HDES 3 and TTPBP could disrupt the asphaltenes structure, thus stabilizing them in the oleic environment.

Parametric Investigation of Wettability Alteration of Reservoir Rocks by Asphaltene Deposition: Experimental and Modeling Approaches

Rock wettability plays an important role in water flooding process as it controls fluid flow, oil recovery and distribution of residual oil in any oil reservoir. In this context, polar oil components such as asphaltene contents may adsorb onto the pore mineral surfaces and alter wettability of the reservoir rock. Due to this importance, this study aims to investigate the effects of different parameters such as concentration of asphaltene, salinity, temperature and time on the rock wettability alteration process. For this purpose, dynamic contact angle measurement was performed. The results showed that the increment of asphaltene concentration in the oleic phase changes the wettability of water-wet sandstone rock to oil-wet condition; the increase in the concentration of asphaltene fraction from 0.1 to 5.0 g/lit increased the contact angle from 0 to 97 degrees. In addition, the increase in the brine salinity from 500 to 8000 ppm increased the ability of asphaltene to adsorb on the rock surface and consequently, increased oil wetness; the equivalent contact angle changed from 0 to 113 degree for 5 g/lit asphaltene content after 192 hours. Moreover, the results illustrated that a rise in temperature from 40 to 70 o C accelerates adsorption of asphaltene, but it has not significant effect on the final contact angle. Furthermore, the Adaptive Neuro-Fuzzy Inference System (ANFIS) is incorporated into the Particle Swarm Optimization (PSO) algorithm to correlate contact angle with the aforementioned parameters. To this end, the obtained experimental data are used to train and test the algorithm. The outputs of ANFIS-PSO algorithm are compared with the measured contact angles in both graphical and statistical manners. The training and testing determination coefficients (R 2 ) have been obtained as 0.99091 and 0.98761, respectively. The analysis indicates that the predictive model can be used with a high degree of confidence to investigate the effect of different parameters on wettability alteration

On the size-dependent behavior of drop contact angle in wettability alteration of reservoir rocks to preferentially gas wetting using nanofluid

Wettability alteration of rock surfaces toward gas wetting have been recognized as a practical approach for maximizing the production from the gas condensate reservoirs. Most of the reported work in this area applied the so called sessile drop contact angle measurement technique to examine the change in wetting state of a surface. However, the size-dependent wetting behavior of drop which could affect the exact determination of wettability and wettability changes was not well discussed in the previous studies. Therefore, in this work, the size dependency of contact angle for four different liquid-solid-gas systems; i.e., water-calcite-air, water-treated calcite-air (nanofluid treated calcite), oil-calcite-air, and oil-treated calcite-air, were investigated. To provide a better understanding of the displacement of reservoir gas and liquid following the wettability alteration process, a dynamic contact angle measurement approach was designed. The effect of drop size and surface roughness on the wetting state of calcite rock samples at the initial and altered condition of wettability was then investigated through experimental and modeling approaches. The surface roughness of calcite samples and drop contact angles were determined using Atomic Force Microscopy and Low bond axisymmetric drop shape analysis method, respectively. Analysis of results demonstrated that size dependency of contact angle imposed an error as high as 22.2° on the measurement of achieved wettability alteration in the case of water-calcite/treated calcite-air system. On the basis of calculated pseudo-line tension from the modeling schemes, it was also revealed that the surface roughness had a significant impact on wettability measurements. Both low and high pseudo-line tension values of order 10−9 and 10−6 N, respectively, could dictate some level of errors in contact angle measurements. However, high values were supposed to have a considerable degree of importance in gas condensate applications. The results of this study could provide a better understanding of the contact angle measurement experiments for petroleum engineers to evaluate the wettability alteration schemes.

A Numerical Investigation of Low-Salinity Waterflooding Capability to Enhanced Oil Recovery

Low-salinity water flooding (LSWF) is one of techniques that can be used to improve oil production and has gained a significant attention in these days because of its advantages over conventional water flooding and chemical flooding. Even though many mechanisms have been recommended on an extra oil recovery achieved using LSWF process, the principle fundamental of the mechanism is still not fully understood. This research paper investigates the potential of oil recovery in an onshore sandstone reservoir using LSWF. A field-scale three–dimensional reservoir model has been developed via CMG’s GEM compositional simulator where the model validated against a real production field data that were in good agreement with a deviation value of 8%. The primary mechanism of LSWF has been identified by providing incremental oil recovery due to a multi-component ion exchange mechanism that causes wettability alteration of reservoir rock from oil-wet to water-wet. The sensitivity study showed that LSWF provides a higher accumulative oil production compared to conventional high salinity water injection with 13.5 and 12 MMSTB. Moreover, the early time of low saline brine injection can provide a maximum oil recovery up to 71%. Therefore, implementing this scenario immediately after the primary recovery, it provides production benefits in both secondary and tertiary method. The oil recover factor increased to 75.5% with the increasing of brine injection rate up to an optimum value of 5320 bbl/d. A reservoir temperature also influenced the ion exchange wettability alteration during LSWF in which as the temperature increasing enhances the oil recovery. Therefore, a high temperature sandstone reservoir will be a potential candidate for LSWF.

Toward a mechanistic understanding of wettability alteration in reservoir rocks using silica nanoparticles

Traditional concepts of simple liquid spreading may not apply to nanoparticle-fluids. Most investigations pertaining to the wettability alteration of solid surfaces due to the presence of nanoparticles in the fluid are oversimplified, i.e. nanoparticles dispersed in DI-water and smooth, homogeneous, and clean surfaces have been used. From a practical enhanced oil recovery (EOR) point of view, the nanoparticles must be dispersed in either seawater or high salinity formation water containing diverse types and concentrations of ions. These ions interact with the electrostatic properties of the nanoparticles. Likewise, the oil phase may contain many surface active components like asphaltene and naphthenic acids which can interact with nanoparticles at oil-water and oil-rock interface. In reality, the rock sample is a heterogeneous, non-smooth, mixed-wet substrate with a diverse mineralogical composition. The electrical charge of minerals can vary when contacted with an ionic fluid. This can alter the electrostatic repulsion between substrate and nanoparticles and consequently the substrate can either attract or repel charged particles, including nanoparticles. Hence, the role of nanoparticles must be evaluated considering multicomponent complex fluids and real formation rock. Despite numerous reports regarding the wettability alteration of reservoir rock from oil-wet to water-wet by nanoparticles, some inherent limitations in the wettability alteration experiments prevent conclusions about the performance of nanoparticles in practical complex conditions. For instance, the wettability alteration by nanoparticles is often determined by contact angle measurements. In this method, the substrates are either aged with (immersed in) nanoparticle-fluids before conducting the experiments or contacted with nanoparticle-fluids before attachment of the oil droplet on the rock surface. Hence, in both cases, before initiating the contact angle measurements, the nanoparticles would already exist at the oil-rock interface possibly giving inaccurate measurements. The objective of this work is to investigate the mechanism of wettability alteration by silica nanoparticles pre-existing on the rock interface (conventional contact angle measurements) and using a new displacement contact angle method to better mimic the scenario of injecting a nanoparticle fluid into the reservoir already containing formation brine. The impact of pre-existing nanoparticles at the oil-rock interface (in the conventional contact angle measurements) on the contact angle measurements are examined for simple (n-decane, NaCl brine, and pure substrates) and complex (crude oil, seawater, and reservoir rock) systems on various wetting conditions of substrates (water-wet and oil-wet). The nanoparticles are dispersed in seawater using our H+ protected method [1]. Then, the effect of surface and nanoparticle charge on the contact angle is evaluated by adjusting the aqueous phase salinity. We also differentiate between the disjoining pressure mechanism and diffusion of silica nanoparticles through the oil phase by testing the attachment of nanoparticles on the rock surface.

Production improvement in gas condensate reservoirs by wettability alteration, using superamphiphobic titanium oxide nanofluid

Many gas condensate reservoirs suffer a loss in productivity owing to accumulation of liquid in near-wellbore region. Wettability alteration of reservoir rock from liquid-wetting to gas-wetting appears to be a promising technique for elimination of the condensate blockage. In this paper, we report use of a superamphiphobic nanofluid containing TiO2 nanoparticles and low surface energy materials as polytetrafluoroethylene and trichloro(1H,1H,2H,2H-perfluorooctyl)silane to change the wettability of the carbonate reservoir rock to ultra gas-wetting. The utilization of nanofluid in the wettability alteration of carbonate rocks to gas-wetting in core scale has not been reported already and is still an ongoing issue. Contact angle measurements was conducted to investigate the wettability of carbonate core plugs in presence of nanofluid. It was found that the novel formulated nanofluid used in this work can remarkably change the wettability of the rock from both strongly water- and oil-wetting to highly gas-wetting condition. The adsorption of nanoparticles on the rock and formation of nano/submicron surface roughness was verified by Scanning Electron Microscope (SEM) and Stylus Profilometer (SP) analyses. Using free imbibition test, we showed that the nanofluid can imbibe interestingly into the core sample, resulting in notable ultimate gas-condensate liquid recovery. Moreover, we studied the effect of nanofluid on relative permeability and recovery performance of gas/water and gas/oil systems for a carbonate core. The result of coreflooding tests demonstrates that the relative permeability of both gas and liquid phase increased significantly as well as the liquid phase recovery enhanced greatly after the wettability alteration to gas-wetting.

Wettability alteration of reservoir rocks to gas wetting condition: A comparative study

AbstractProductivity of gas condensate reservoirs reduces significantly due to the near wellbore condensate/water blockage phenomenon. A novel, permanent solution to alleviate this problem is near wellbore wettability alteration of reservoir rocks to preferentially gas wetting conditions; industrial chemical materials are good candidates for this purpose, because of their eco‐friendly characteristics, economical price, and mass production. In this paper, a comparative study is conducted on two industrial fluorinated chemicals, MariSeal 800 and SurfaPore M. Static and dynamic contact angle measurements, spontaneous imbibition, and core flooding tests were conducted to investigate the effect of utilized chemical agents on surface wetting behaviour and fluid flow characteristics of rock samples. Contact angle measurements demonstrate that the liquid phase is changed to a non‐wetting phase after chemical treatment and MariSeal 800 has a greater potential to decrease the surface free energy of the calcite surface. Although both chemicals reveal great potential in static contact angle measurements, further experiments were conducted to distinguish between their abilities. Spontaneous air liquid imbibition tests and endpoint relative permeability measurements approved the potential of utilized chemicals to improve liquid phase mobility and decrease critical condensate saturation, which improve production parameters and reservoir productivity. Liquid phase endpoint relative permeabilities of sandstone core samples were improved by factors of 1.74 and 2.62; furthermore, irreducible liquid phase saturations were decreased by factors of 0.68 and 0.5 using MariSeal 800 and SurfaPore M chemicals. The results of this research help efficient selection of chemical agents for further field applications.

Toward a hydrocarbon-based chemical for wettability alteration of reservoir rocks to gas wetting condition: Implications to gas condensate reservoirs

Recently, wettability alteration has been much attended by researchers for studying well productivity improvement in gas condensate reservoirs. Previous studies in this area only utilized water/alcohol based chemicals for this purpose. While, hydrocarbon nature of the blocked condensate in retrograde gas reservoirs, may motivate application of hydrocarbon based chemical agents. In this study, a new hydrocarbon based wettability modifier is introduced to alter wettability of carbonate and sandstone rocks to preferentially gas wetting condition. Static and dynamic contact angle measurements, spontaneous imbibition and core flooding tests were conducted to investigate the effect of proposed chemical on surface wetting behavior, and fluid flow characteristics at core scale. SEM, EDX, EDX map and FTIR tests are used to characterize the adsorbed chemical layer and also to endorse the adsorption of fluorinated chemicals on both sandstone and carbonate rock surfaces. It is inferred from the results of contact angle hysteresis at different levels of tilt angle that the surface roughness increased as a result of treatment with the new chemical. Measurements of surface free energy of calcite thin section at different tilt angles, by means of dynamic contact angle method, showed a significance decrease due to treatment with the new chemical, the factor of reduction ranges from 0.24 to 0.03. The results of air-water and air-n-decane spontaneous imbibition tests showed remarkable decrease in the ultimate imbibed liquids by a factor of 0.14 and 0.34, respectively. Also, core flooding experiment results demonstrated improvement of liquid phase endpoint relative permeability by a factor of 1.73 as a result of treatment with the proposed chemical fluid. The proposed chemical is miscible with dropped out condensate and does not suffer from instability due to reservoir brine salinity. Effectiveness, as well as hydrocarbon base of the proposed chemical makes it an attractive candidate for possible applications to enhance condensate recovery due to both condensate and water blockage in gas reservoirs by wettability alteration technique.

Surface functionalization of silica nanoparticles to improve the performance of water flooding in oil wet reservoirs

Over the past few years, increasing attention has been devoted to the applications of special engineered nanoparticles in enhancing oil recovery. Earlier studies reported the effects of these particles on wettability alteration of reservoir rock. The present study presents a new method for modifying the surface properties of silica nanoparticles to make them more effective for enhancing oil recovery purposes. Contact angle, interfacial tension measurements, and core flood experiments were performed to examine the effects of these surface-modified nanoparticles on the interfacial interactions of injected water and reservoir rock and oil sample. To improve the performance of water flooding, surface-modified nanoparticles were produced in laboratory and it was found that amine-functionalized silica nanoparticles are significantly more effective than typical nanoparticles. Experimental results revealed that both contact angle and interfacial tension decrease more in the presence of functionalized nanoparticles. These results were confirmed by performing core flood tests which showed an 18% increase in total oil recovery compared to typical nanoparticles. Therefore, amine-functionalized silica nanoparticles could be more effective than typical nanoparticles in increasing the sweep efficiency by changing the wettability of reservoir rock and reducing oil/water interfacial tension. Moreover, it was observed that there is an optimum concentration for contact angle and interfacial tension reduced by nanoparticles and in concentration more than this threshold value the interfacial tension starts to increase slightly.

Exploring beneficial structural features of ionic surfactants for wettability alteration of carbonate rocks using QSPR modeling technique

Surfactant induced wettability alteration of reservoir rocks is an efficient process that enhances oil recovery of carbonate reservoirs. Finding a suitable surfactant for such a process is an interesting challenge in petroleum industry. To this purpose, generating a database of surfactant properties would be a good idea but property measurement of hundreds of surfactants and then screening them is a highly time consuming and expensive method. Therefore, the application of a mathematical model for prediction of surfactant properties may well be so helpful for our purpose. Quantitative structure-property relationship (QSPR) is a mathematical model that relates a specific property of materials to their structural characteristics. For the sake of QSPR modeling a dataset of 24 structurally different surfactants was created through the measurement of contact angles (as the most important surfactant characteristic in the wettability alteration process). Contact angle measurement was carried out through imaging a drop of n-decane as the model oil resting on a carbonate rock which has spent 2days immersed in surfactant solution. For this dataset a linear QSPR model of oil contact angle on carbonate rocks was derived using genetic algorithm based on multi-linear regression (GA-MLR) and verified by internal and external validation metrics. From a descriptive point of view, descriptors of the proposed model have a mechanistic interpretation and give an insight to the desired structural features enhancing wettability alteration ability of surfactants.

Experimental assessment of a lysine derivative surfactant for enhanced oil recovery in carbonate rocks: Mechanistic and core displacement analysis

Abstract Enhanced oil recovery (EOR) from carbonate reservoirs is of great challenge due to the complex geology that originated from high rock heterogeneity and viscous fingering phenomenon during a displacement process. One of the highly applicable EOR approaches is the utilization of surfactant especially for the aims of foam generation, wettability alteration, emulsion stability and well stimulation in petroleum industry. The dominant mechanisms of surfactant for increasing oil production are wettability alteration of reservoir rock and interfacial tension (IFT) reduction of oil-water system resulting in higher sweep efficiency by diminishing the adverse capillary forces existing in the porous media and easier flow of the residual oil toward the producing wells. In the present study, (S) 2-amino-6-dodecanamidohexanoic acid as an amino acid-based surfactant, is proposed in order to evaluate an EOR application. Firstly, the pH, density and viscosity of the surfactant solutions were measured regarding the impact of salt concentration. Afterwards, IFT and wettability tests were conducted by means of pendent drop and sessile drop methods, respectively. The impact of salt concentration was also examined on the IFT behavior. Moreover, the recovery potential of the proposed amino acid-based surfactant via core displacement test was compared with a traditional brine injection process. Consequently, it is found out that increasing salt concentration has an increasing effect on both IFT trend and the values of critical micelle concentration. Additionally, change in carbonate rock wettability from oil-wet to neutral-wet was also observed. Finally, it is proved that surfactant flooding can improve the oil recovery factor more than the time at which water injection is used.

Nanoparticles influence on wetting behaviour of fractured limestone formation

Nanoparticles have gained considerable interest in recent times for oil recovery purposes owing to significant capabilities in wettability alteration of reservoir rocks. Wettability is a key factor controlling displacement efficiency and ultimate recovery of oil. The present study investigates the influence of zirconium (IV) oxide (ZrO2) and nickel (II) oxide (NiO) nanoparticles on the wetting preference of fractured (oil-wet) limestone formations. Wettability was assessed through SEM, AFM and contact angle. The potentials of the nanoparticles to alter oil-wet calcite substrates water wet, was experimentally tested at low nanoparticle concentrations (0.004–0.05wt%). Quite similar behaviour was observed for both nanoparticles at the same particle concentration; while ZrO2 demonstrated a better efficiency by altering strongly oil-wet (water contact angle θ=152°) calcite substrates into a strongly water-wet (θ=44°) state, NiO changed wettability to an intermediate-wet condition (θ=86°) at 0.05wt% nanoparticle concentration. We conclude that ZrO2 is very efficient in terms of inducing strong water-wettability; and ZrO2 based nanofluids have a high potential as EOR agents.

Experimental investigation the effect of nanoparticles on micellization behavior of a surfactant: Application to EOR

ABSTRACTChemical stimulation such as surfactant flooding in petroleum reservoirs makes efforts to produce remained oil and improve sweep efficiency by means of different phenomena such as lowering interfacial tension and wettability alteration of reservoir rock. Implementing concentration of surfactant through surfactant flooding is one of the big challenges while interfacial tension between surfactant solution and oil after certain concentration involves little changes such as critical micelle concentration (CMC). This article highlights the effect of nanosilica on CMC of Zyziphus Spina Christi, as sugar-based surfactant, in aqueous solutions for enhanced oil recovery and reservoir stimulation purposes. A conductivity approach was selected to assess the CMC of the introduced surfactant in aqueous solution at 25°C. The influence of nanosilica concentrations on CMC variation of introduced surfactant is considered. It is found that CMC of introduced surfactant decreased while the concentration of the nanosilica increased. Results from this study can aim in optimum condition selection of surfactant flooding as an enhanced oil recovery ends.

Experimental investigation of wettability alteration on residual oil saturation using nonionic surfactants: Capillary pressure measurement

Abstract Introducing the novel technique for enhancing oil recovery from available petroleum reservoirs is one of the important issues in future energy demands. Among of all operative factors, wettability may be the foremost parameter affecting residual oil saturation in all stage of oil recovery. Although wettability alteration is one of the methods which enhance oil recovery from the petroleum reservoir. Recently, the studies which focused on this subject were more than the past and many contributions have been made on this area. The main objective of the current study is experimentally investigation of the two nonionic surfactants effects on altering wettability of reservoir rocks. Purpose of this work is to change the wettability to preferentially the water-wet condition. Also reducing the residual oil saturation (Sor) is the other purpose of this work. The wettability alteration of reservoir rock is measured by two main quantitative methods namely contact angle and the USBM methods. Results of this study showed that surfactant flooding is more effective in oil-wet rocks to change their wettability and consequently reducing Sor to a low value. Cedar (Zizyphus Spina Christi) is low priced, absolutely natural, and abundantly accessible in the Middle East and Central Asia. Based on the results, this material can be used as a chemical surfactant in field for enhancing oil recovery.

Effect of Natural Leaf-derived Surfactants on Wettability Alteration and Interfacial Tension Reduction in Water-oil System: EOR Application

In this study, two types of plants based natural cationic surfactants, named Mulberry and Henna are introduced and the application of these natural surfactants in wettability alteration of reservoir rock and reducing the interfacial tension of water-oil system is investigated. For this purpose, two natural-based surfactants were extracted from the leaves of the trees of addressed plants and then the interfacial tension (IFT) values between oil and natural surfactant solution and also the contact angle values between natural surfactant solution and rock sample were measured. The results demonstrated that Mulberry extract was able to lower the interfacial tension between oil and distilled water from 43.9 to 4.01 mN/m, while Henna extract could reduce the IFT from 43.9 to 3.05 mN/m. These natural surfactants were also able to reduce the contact angle of rock/fluid system which shows the wettability is altering to water wet system and so it may increase recovery factor by reducing residual oil saturation and Henna extract could reduce the contact angle more than that of Mulberry leaf extract. According to these results in addition to the low price of generating natural surfactants, the feasibility of using these kinds of surfactants in future oil recovery processes is of major concern.

Wettability Alteration of Reservoir Rocks from Liquid Wetting to Gas Wetting Using Nanofluid

Well productivity in gas condensate reservoirs is reduced by condensate banking when the bottom hole flowing pressure drops below the dew point pressure. Among the several methods which have been proposed for condensate removal, wettability alteration of reservoir rock to intermediate gas wetting in the near wellbore region appears to be one of the most promising techniques. In this work, we report use of a nanofluid to change the wettability of the carbonate and sandstone rocks to intermediate gas wetting. Application of nanofluid in the wettability alteration of carbonate and sandstone rocks to gas wetting has not been reported previously and is still an ongoing subject. Static and dynamic contact angle measurements, along with imbibition tests, have been performed to investigate the wettability of carbonate and sandstone rocks in presence of nanofluid. It was found that the nanofluid used in this work can considerably change the wettability of both surfaces to preferentially gas wetting in just one day of ageing time. We also report the effect of initial oil saturation and ageing time on the nanofluid capability for wettability change. Initial oil saturation reduces the impact of the nanofluid on wettability change, and hence, a pre-treatment before using nanofluid is necessary. In addition to these small slab-scale experiments, applicability of nanofluid in wettability alteration of sandstone rocks to gas wetting is also investigated in core scale. The results of core displacement tests confirm the ability of nanofluid to change the rock wettability from liquid wetting to gas wetting in core samples. They also show the effectiveness of chemical treatment in subsurface conditions.

Numerical Simulation of Surfactant Flooding in Darcy Scale Flow

One of the methods that is used nowadays in enhanced oil recovery is surfactant flooding. The main mechanisms of surfactant flooding in reservoir consist of reduction of interfacial tension between water and oil and modification of rock wettability. In this study, the authors simulate the surfactant injection process in Darcy scale and in one-dimensional, multicomponent, multiphase state, and effects of physical phenomena such as adsorption, dispersion, convection, and exchange between fluids and solids are considered. Wettability alteration of reservoir rock due to presence of surfactant in injected fluid is detected in relative permeability and capillary pressure curves. First, the authors express the governing flow equations in the system and then discretize them. The variables consist of water and oil saturations, surfactant concentration in water phase, water and oil pressures, and velocities in each block. Second, the discretized equations are solved by IMPES method and pressure and saturation variables are calculated and after that, the concentration of surfactant in water phase is calculated. Finally, results of simulation are shown.

Wettability Alteration with Silica Aerogel Nanodispersion

This work studies the wettability alteration using nanoporous silica aerogels for enhanced oil recovery. Water wet flat glass and outcrop sandstone are used for this aim. Modified silica aerogels are synthesized with cheap water glass as the precursor, and ambient pressure drying method. Sessile drop method was used to measure the contact angles. Sandstones with 0° contact angle changed to mixed wet with 88° contact angle, and flat glasses with a 30° contact angle change to 70° contact angle. Results show that silica aerogels have a great potential in wettability alteration of reservoir rocks by adsorption and deposition mechanisms.