Wettability Modifiers Research Articles

Experimental Investigation of Wettability Alteration in Oil-Wet Reservoirs Containing Heavy Oil

Summary Solvent injection is an effective way to lower the viscosity of heavy oil and is considered when thermal techniques are not practically applicable. However, for the economic success of the method, large fractions of the injected solvent must be recovered. This requires further treatments of the reservoir, including water injection with chemicals to penetrate into the oil-wet matrix by changing the wettability. In this paper, we investigate the effect of wettability alteration of the oil-wet rock on solvent as well as oil recovery. Different wettability-alteration agents were tested, including cationic and anionic surfactants, ionic liquids, nanofluids, high-pH solutions, and low-salinity water. The potential of these materials to modify the wettability of aged sandstone and limestone samples was evaluated by use of imbibition tests. After conducting a total of 35 experiments, the most-promising wettability-alteration agents were identified to be anionic surfactants and high-pH solutions in addition to low-salinity water for the sandstone cases. Ion-pair interaction in sandstone and the dissolution of mixed-wet clay particles in carbonate are the main mechanisms of wettability alteration by those chemicals. Cationic surfactants and high-pH solutions were identified as the best wettability modifiers for the limestone samples. Although cationic surfactant changes the wettability by the ion-pair-interaction mechanism, the pH solution is believed to restore the water-wetness by decreasing the attraction forces between calcite and organic components. Ionic liquid at low concentration is able to alter the wettability of carbonate better than other conventional wettability modifiers. One important finding of this work is that solvent injection in heavy-oil-containing reservoirs is essential to condition the reservoir (i.e., to dilute the heavy oil before any wettability-alteration treatment can take place).

Optimization of Fluorinated Wettability Modifiers for Gas/Condensate Carbonate Reservoirs

Summary Significant reduction in well productivity of gas/condensate reservoirs occurs because of reduced gas mobility caused by the presence of condensate/water liquid phases around the wellbore. There are certain fluorinated wettability modifiers that are capable of delivering a good level of oil and water repellency to the rock surface, making it intermediate gas-wet and alleviating such liquid blockages. The main objective of this experimental work has been to evaluate the performance of such chemicals for wettability alteration of carbonate rocks, which have received much less attention in comparison with sandstone rocks. Screening tests, including contact-angle measurements, unsteady-state-flow tests, and compatibility tests with brine, were performed by use of mainly anionic and nonionic fluorosurfactants. Results demonstrated that on positively charged carbonate surfaces, the anionic chemicals were sufficiently effective to repel the liquid phase, whereas the nonionic chemicals showed an excellent stability in brine media. A new approach of combining anionic and nonionic chemical agents was proposed to benefit from these two positive features of an integrated chemical solution. A number of low- and high-permeability carbonate-core samples were successfully treated by use of chemicals selected through screening tests. Optimization of the solution composition and its filtration before injecting it into the core proved very effective in reducing/eliminating the risk of possible permeability damage because of deposition of large chemical aggregates on the rock surface. The chemical solution optimized in this study can be considered as a potential wettability modifier for mitigating the negative impact of condensate/water banking in gas/condensate carbonate reservoirs.

Carbonate and sandstone reservoirs wettability improvement without using surfactants for Chemical Enhanced Oil Recovery (C-EOR)

In this paper, we have been proposed the preparation of Silica–MWCNT nanohybrid that can increase the water wettability of carbonate and sandstone reservoirs. Chemical agents such as surfactants have been used as wettability modifiers to increase oil recovery from oil-wet carbonate and sandstone reservoirs. Addition of chemical compounds such as polymers, ionic materials and nanoparticles can improve the effectiveness of the mentioned chemical agents.The effectiveness of nanohybrids without using surfactants has not been reported yet and it is still in its infancy. In this work, the effect of MWCNT–SiO2 nanohybrid-based nanofluids on the wettability alteration of a carbonate and a sandstone reservoir rocks was experimentally studied. Therefore, MWCNT–Silica nanohybrid has been prepared by adding the suitable amount of MWCNT in situ of silica nanostructure preparation. In this research, MWCNT–Silica nanohybrid was prepared with ultrasound assisted sol–gel method and characterized with X-ray diffraction (XRD), Field Emission Scanning Electron Microscopy (FE-SEM) and Transmission Electron Microscopy (TEM). The effect of the related nanofluid on the wettability of carbonate and sandstone rocks was investigated by measuring contact angle and interfacial tension. Results show that the nanofluid could significantly change the water wettability of the mentioned rocks from oil-wet to water-wet condition without using surfactant.

Impact of Gas–Condensate Composition and Interfacial Tension on Oil-Repellency Strength of Wettability Modifiers

Productivity of gas–condensate wells can significantly be declined as the condensate bank evolves around the wellbore. Wettability alteration of formation minerals from strongly liquid-wet to intermediate gas-wet conditions using liquid-repellent fluorinated chemicals has shown promising results to mitigate such liquid-blockage issues. This paper, for the first time, presents the results of unique contact angle measurements conducted on the treated carbonate substrates using synthetic gas–condensate fluids. The impact of hydrocarbon composition and interfacial tension (IFT) on the condensate wetting tendency was investigated using various binary and multi-component mixtures at ambient temperature. A high-pressure high-temperature (HPHT) drop shape analysis setup was customized to perform the static contact angle tests. The generality of the new findings from these measurements was also confirmed using dynamic unsteady-state flow tests. The results demonstrated that the wetting tendency of the condensate is significantly decreased as IFT increases and/or the hydrocarbon composition becomes heavier. The C1–nC4 condensate drop, for instance, completely wetted out the treated surface at both low- and high-IFT limits of 1 and 10 mN/m, whereas the C1–nC10 sample resulted in contact angles of 30° and 65° at similar IFT conditions, respectively. The oil-repellency strength of the fluorochemical was also evaluated at high temperatures of 50 and 100 °C with promising results. In this paper, the initial investigations on the impact of surface roughness on the solid surface wettability was carried out, demonstrating the positive impact of surface roughness on increasing the desired level of oil repellency achieved after the wettability alteration. The new findings from this work provide important guidelines in design and application of wettability modifiers for gas–condensate reservoirs.

Experimental investigation of SiO2 nanoparticles on enhanced oil recovery of carbonate reservoirs

Wettability alteration is an important method to increase oil recovery from oil-wet carbonate reservoirs. Chemical agents are used as wettability modifiers in carbonate systems; however, the role of Nanoparticles in this field is still in its infancy and consequently has attracted the attention of many researchers in the last decade. In this work, the impact of SiO2 Nanoparticles on the wettability of a carbonate reservoir rock was experimentally studied. The impact of these Nanoparticles on the wettability of carbonate systems is still in its infancy. For this purpose, the effect of Nanofluid’s concentration on wettability and interfacial tension were investigated to determine the optimum concentration of Nanofluid for injection into core samples. The result suggests that a concentration of 4 g/L of Nanofluid could significantly alter the wettability of the rock from a strongly oil-wet to a strongly water-wet condition. Moreover, we studied the Nanofluids’ potential in enhanced oil recovery of oil-wet core plugs. The results show that a considerable amount of oil can be recovered right after start of water injection to the aged core plug with Nano fluid.

A Laboratory Investigation into Wettability Alteration of Carbonate Rock by Surfactants: The Effect of Salinity, pH, and Surfactant Concentration

Wettability alteration is an important method for i ncreasing oil recovery from oil-wet carbonate reservoirs. Chemical agents like surfactants are kn own as wettability modifiers in carbonate systems. Oil can be recovered from initially oil-wet carbona te reservoirs by wettability alteration from oil-we t to water-wet condition with adding dilute surfactan t and electrolyte solutions. This paper investigate s the effects of brine concentration, surfactant conc entration, and the pH of injection water on the wettability alteration of carbonate reservoirs by d ifferent class of surfactants. Scanning electron microscopy images verified the formation of surfact ant layer surfaces and the adsorption of surfactant molecules on the rock. The results revealed that TX -100, as a nonionic surfactant, and CTAB, as a cationic surfactant, were better wettability modifi ers than SDS, as an anionic surfactant, for carbona te rocks. At the concentration of 1 wt.% and higher, t he contact angle reduction was approximately unchanged. The results also proved that there was a n optimum salinity for the maximum wettability alteration by surfactants. Increasing the pH of agi ng fluid resulted in better wettability alteration by CTAB, while, in the case of SDS, the wettability al teration was reduced. Acidic conditions had a negligible effect on the wetting behavior of TX-100 .

Wettability alteration to intermediate gas-wetting in low-permeability gas-condensate reservoirs

Gas-condensate reservoirs experience significant productivity losses as reservoir pressure drops below the dew point due to condensate accumulation and water blocking and the subsequent reduction in gas relative permeability. One potential way to overcome this problem is to alter reservoir wettability to gas-wetting to reduce condensate accumulation and water blocking in the near wellbore and maintain high productivity. The major goal of this work was to study the mobility of the gas and liquid phase (both water and oil) before and after wettability alteration from strong liquid-wetting to intermediate gas-wetting. For this purpose, in addition to relative permeability measurements, we also conducted various other tests to demonstrate that liquid mobility can be improved significantly due to wettability alteration. As wettability modifiers, fluorinated polymers are capable of delivering a good level of oil and water repellency to the rock surface, making it intermediate gas-wet and alleviating such liquid blockage under high temperature. The contact angle analyses, capillary rise, flow tests, and imbibition spontaneous tests were used to estimate the effect of treatments on wettability. Experimental results demonstrated that the fluorinated polymers can alter the wettability of cores from strong liquid-wetting to gas-wetting, which could decrease the amount of water invaded and resided in the gas formation. Core flood test results demonstrated that the relative permeabilities of both the gas and the liquid phases were increased significantly after the wettability alteration to preferential gas-wetness. The residual liquid saturation was decreased, and the gas production was enhanced greatly due to the wettability alteration. These results imply that gas well deliverability may increase substantially when wettability is altered to intermediate gas-wetting. Efficiency in the extraction of natural gas is important to improve the productivity of gas-condensate reservoirs where liquid accumulates, which is beneficial for the economic and environmental considerations of the oil and gas industry.

Quantum chemical characterization of zwitterionic structures: Supramolecular complexes for modifying the wettability of oil–water–limestone system

In this work, we present a quantum chemical study pertaining to some supramolecular complexes acting as wettability modifiers of oil–water–limestone system. The complexes studied are derived from zwitterionic liquids of the types N′-alkyl-bis, N-alquenil, N-cycloalkyl, N-amyl-bis-beta amino acid or salts acting as sparkling agents. We studied two molecules of zwitterionic liquids (ZL10 and ZL13), HOMO and LUMO levels, and the energy gap between them, were calculated, as well as the electron affinity (EA) and ionization potential (IP), chemical potential, chemical hardness, chemical electrophilicity index and selectivity descriptors such Fukui indices. In this work, electrochemical comparison was realized with cocamidopropyl betaine (CPB), which is a structure zwitterionic liquid type, nowadays widely applied in enhanced recovery processes.

Wettability Alteration of Sandstone Cores by Alumina-Based Nanofluids

Wettability alteration can occur at different stages during the producing life of a reservoir. Oil recovery from oil-wet reservoirs can significantly be increased by altering its wettability from an oil-wet to a strongly water-wet condition. Chemical agents such as surfactants are known as wettability modifiers in oil-wet systems. More recently, nanofluids prepared by dispersing nanoparticles in several liquid agents have been considered as potential wettability modifiers. In this work, the effectiveness of alumina-based nanofluids in altering the wettability of sandstone cores with an induced oil-wet wettability was experimentally studied. Eight nanofluids with different nanoparticles concentration, ranging from 100 ppm to 10000 ppm, were prepared by dispersing alumina nanoparticles in an anionic commercial surfactant. The effect of nanofluids on wettability alteration was investigated by contact angle and imbibition tests, and it was shown that designed nanofluids could significantly change the wettabil...

Density Functional Theoretical Study of the Interaction of Geminal Zwitterionic Liquids with Limestone, Regarding the Behavior of the Wettability Parameter

Zwitterionic liquids have a wide variety of applications in enhanced oil recovery (EOR). In particular, geminal zwitterionic substances have been used as wettability modifiers of limestone, dolomites, and sandstones at high temperatures and pressures. The understanding of the interaction mechanisms of such molecules with the limestone surface is an important step toward the comprehension of the modification in wettability. In the study here presented, the interaction energies of limestone with geminal zwitterionic liquids of the type bis-N-alkyl polyether were calculated within the framework of the density functional theory (DFT). With the use of the DMOL3 library of the Material Studio Software (a DFT-based computational code), we calculated the interaction energies of the bis-N-alkyl polyether liquids, asphaltene with the limestone rocks.

Wettability Alteration in Carbonates using Zirconium Oxide Nanofluids: EOR Implications

Wettability alteration is an important method to increase oil recovery from oil-wet carbonate reservoirs. Chemical agents like surfactants are known as wettability modifiers in carbonate systems. However, the effectiveness of these agents can be increased by the addition of chemicals such as polymers, ionic materials, and nanoparticles. The impacts of nanoparticles on the wettability of carbonate systems have not been reported yet, and it is still in its infancy. In this work, the effect of ZrO2-based nanofluids on the wettability alteration of a carbonate reservoir rock was experimentally studied. Several nanofluids were made composed of ZrO2 nanoparticles and mixtures of nonionic surfactants. The effect of nanofluids on the wettability of carbonate samples were investigated by measuring the contact angles, and it was shown that designed nanofluids could significantly change the wettability of the rock from a strongly oil-wet to a strongly water-wet condition. Scanning electron microscopy (SEM) images and X-ray Diffraction (XRD) data verify adsorption of nanoparticles on the rock and formation of nanotextured surfaces. Moreover, this paper reports the quick imbibitions of ZrO2 nanofluids into oil-wet core plugs saturated with stock tank oil. The results show that a considerable amount of oil can be quickly recovered by free imbibitions of the nanofluids into the core plugs. A theoretical approach is also presented to explain the wettability alteration by formation of composite nanotextured surfaces.

Ultra-thin films of cationic amphiphilic poly(2-(dimethylamino)ethyl methacrylate) based block copolymers as surface wettability modifiers

Abstract Ultra-thin films of cationic amphiphilic block and statistical copolymers were applied on silica surfaces from aqueous solutions through electrostatic interactions, and the resulting modification in the wettability of the surfaces was studied. A copolymer series from 2-(dimethylamino)ethyl methacrylate with methyl methacrylate and butyl methacrylate was polymerized by ATRP. Subsequently, the conformation of the polymers in aqueous solutions was studied by surface tension measurements, dynamic light scattering, 1H NMR and cryogenic transmission electron microscopy. Unimeric conformation, equilibrium micelles or frozen micellar structures were observed, depending on polymer composition and the ionic strength of the solution. The polymers were applied on silica from aqueous solutions by either spin coating or adsorption. The formed ultra-thin film surfaces were studied by AFM and water contact angle measurements. The spin-coated surfaces were highly hydrophilic with rapidly dropping contact angles, whereas the surfaces prepared by adsorption had stable water contact angles between 30–60°, depending on polymer. The difference between the spin-coated and adsorbed surfaces is explained by the formation of a monolayer in the adsorbed surfaces.

Toward Field-Scale Wettability Modification—The Limitations of Diffusive Transport

Summary Densely-fractured oil-wet carbonate fields pose a true challenge for oil recovery that traditional primary and secondary processes fail to meet. The difficulty arises from the combination of two unfavorable characteristics: First, the dense fracturing frustrates an efficient waterflood; second, because of the oil-wetness, the water pressure exceeds the oil pressure inside the matrix blocks, thus inhibiting spontaneous imbibition of water. In the past decade, using a new class of surfactants, enhanced oil recovery (EOR) researchers have studied the options to chemically revert the wettability of carbonate rock without drastically decreasing the oil-water interfacial tension. These chemicals, termed "wettability modifiers" (WMs), effectively reverse the sign of capillary pressure at the prevalent saturation. With the oil pressure exceeding the water pressure, the capillary pressure becomes the driving force for oil expulsion from the matrix and into the fracture system. Previous publications on chemical wettability modification focused on the performance of different chemical wettability modifiers for a chosen rock/oil/brine system. In some cases, they demonstrated an almost full oil recovery from core plugs. Little attention, however, has been given to the mechanism underlying the transport of the chemical into the matrix block and to the proper scaling of laboratory results to reservoir size. The present study aims to demonstrate that imbibition after wettability modification is diffusion-limited. To this end, the recovery profiles for spontaneous capillary imbibition, as well as for imbibition after wettability modification, are calculated. The results are then used to compare with the data of Amott cell imbibition experiments. It is confirmed that in both cases, the cumulative recovery is initially proportional to the square root of time. Imbibition after wettability modification, however, takes approximately 1,000 times longer than spontaneous capillary imbibition into a water-wet medium. The slow recovery observed in the case of imbibition after wettability modification is in excellent agreement with the assumption that, in the absence of significant spontaneous imbibition, the WM, to unfold its action, must first diffuse into the porous medium. In any diffusion process, the time scale is linked to the square of the length scale of the medium. Therefore, it would take up to 1,000 times longer (an equivalent of 200 years) before the same recovery is obtained from a meter-scale matrix block as is obtained from a centimeter-scale plug in a laboratory in 100 days. Consequently, unless a significantly faster transport mechanism for the wettability modifier is identified, or unless viscous forces or buoyancy enable forced imbibition, the chemical wettability modification of fractured oil-wet carbonate rock does not provide an economically interesting opportunity.