Mechanism Of Wettability Alteration Research Articles

Heavy oil removal using modified polyacrylamide and SDS

Composite systems of surfactants have been extensively applied in the recovery and removal of heavy oil. In this work, the characteristics and mechanisms of heavy oil removal in surfactant-polymer systems (SP) were investigated. The effects of the main factors, including the oil-to-water ratio, washing temperature, washing time, and shear rate, on the oil washing rate (OWR) were analyzed through the response surface methodology (RSM). The results demonstrated the ratio of oil to water had the most significant impact on the OWR compared to other factors. Based on the experimental data and the analysis of variances, a high-precision model was established, and the predicted OWR value was 42.0 % at the formation temperature (50 °C). In addition, the adsorption process of the SP molecules onto quartz silica was well represented by the pseudo-second-order kinetic model and the Freundlich isotherm. This indicates that the SP system has the characteristics of multilayer rebinding and heterogeneous adsorption. On the other hand, the adsorption thermodynamics identified that the adsorption was endothermic and unspontaneous. The dynamic experiments showed that the removal of heavy oil was clean and efficient without secondary adsorption and contamination on the solid surface. Furthermore, the oil removal of the SP system was determined by the mechanism of wettability alteration, utilizing the adsorption of SP molecules onto the solid surface to displace the adsorbed heavy oil molecules. The findings enhance the understanding of heavy oil removal by the surfactant-polymer composite system, which is frequently overlooked in conventional methodologies.

Wettability Alteration Mechanisms in Enhanced Oil Recovery with Surfactants and Nanofluids: A Review with Microfluidic Applications

Modifying reservoir surface wetting properties is an appealing topic to the upstream oil and gas industry for enhancing hydrocarbon recovery as the shifting of reservoir rock surface wetting from oil-wet to water-wet has enhanced the oil recovery by as much as 70–80%. In the last few decades, research has been conducted on core flooding experiments to reveal wettability alteration mechanisms associated with macroscopic fluid flow in reservoirs. In recent years, the microscopic wetting state and fluid distribution behavior have been studied using micromodel experimental techniques to promote the fundamental mechanisms of wettability alteration. To provide the concurrent knowledge and technology development, this comprehensive review focuses on micromodel investigations for wettability alteration in chemical-enhanced oil recovery using surfactants and/or nanofluids that reveal microscopic behaviors on the wetting state, fluid distribution, and their associated mechanisms. This comprehensive review focuses on micromodel investigations for wettability alteration in chemical-enhanced oil recovery using surfactants and/or nanofluids that reveal microscopic behaviors on the wetting state, fluid distribution, and their associated mechanisms. Wettability characteristics and measurement techniques are thoroughly assessed to understand the critical role of wettability for enhanced oil recovery. With the microfluidic-based studies, the effect of relative permeability along with the pore network and wetting order on oil recovery have been discussed. Later on, the new development in phase diagram related to viscus fingering and capillary fingering regime have been reviewed via various micromodels. Then, the wettability alteration mechanisms and governing parameters by surfactant and nanoparticles are summarized. Additionally, recent micromodel experiments on surfactants and nanofluid-assisted enhanced oil recovery are reviewed and listed, along with their fabrication methods.

Application of a Novel Green Nano Polymer for Chemical EOR Purposes in Sandstone Reservoirs: Synergetic Effects of Different Fluid/Fluid and Rock/Fluid Interacting Mechanisms.

In this research, a novel natural-based polymer, the Aloe Vera biopolymer, is used to improve the mobility of the injected water. Unlike most synthetic chemical polymers used for chemical-enhanced oil recovery, the Aloe Vera biopolymer is environmentally friendly, thermally stable in reservoir conditions, and compatible with reservoir rock and fluids. In addition, the efficiency of the Aloe Vera biopolymer was investigated in the presence of a new synthetic nanocomposite composed of KCl-SiO2-xanthan. This chemically enhanced oil recovery method was applied on a sandstone reservoir in Southwest Iran with crude oil with an API gravity of 22°. The Aloe Vera biopolymer's physicochemical characteristics were initially examined using different analytical instruments. The results showed that the Aloe Vera biopolymer is thermally stable under reservoir conditions. In addition, no precipitation occurred with the formation brine at the salinity of 80,000 ppm. The experimental results showed that adding ethanol with a 10% volume percentage reduced interfacial tension to 15.3 mN/m and contact angle to 108°, which was 52.33 and 55.56% of these values, respectively. On the other hand, adding nanocomposite lowered interfacial tension and contact angle values to 4 mN/m and 48°, corresponding to reducing these values by 87.53 and 71.42%, respectively. The rheology results showed that the solutions prepared by Aloe Vera biopolymer, ethanol, and nanocomposite were Newtonian and fitted to the Herschel-Bulkley model. Finally, core flooding results showed that the application of a solution prepared by Aloe Vera biopolymer, ethanol, and nanocomposite was effective in increasing the oil recovery factor, where the maximum oil recovery factor of 73.35% was achieved, which could be attributed to the IFT reduction, wettability alteration, and mobility improvement mechanisms.

Spontaneous imbibition of amphoteric-anionic surfactant and Fe3O4 nanoparticles colloidal mixture for enhanced oil recovery

This study investigates the effects of individual and combined systems on interfacial tension (IFT) and wettability alteration characteristics of a combination mixture of colloidal Fe3O4 nanoparticles and amphoteric-anionic surfactant. Combining a binary of amphoteric-anionic surfactants has resulted in an IFT reduction compared to brine alone. Furthermore, the addition of Fe3O4 nanoparticles at concentrations lower than the critical micelle concentration (CMC) of binary surfactant mixes (<0.15 wt%) resulted in an observed increase in IFT values. However, there is no significant change in IFT around or above the CMC (≥0.15 wt%). The alteration in wettability can be observed through a reduction in contact angle when amphoteric-anionic surfactants and Fe3O4 nanoparticles are combined, resulting in a change from water-wet to strongly water-wet conditions. The findings of the imbibition test also demonstrated that adding 0.01 wt% Fe3O4 colloidal nanoparticles in the surfactant mixture provided an optimal recovery efficiency of 63.17%. The results of this study indicate that a notable improvement in recovery can be observed when the primary mechanism of wettability alteration is achieved and simultaneously supported by IFT reduction.

Influence of wettability alteration on water-blocking effect and gas desorption of coal

To resolve the water-blocking effect that reduces gas extraction after implementing hydraulic measures, alkyl polyglycoside (APG) and polyacrylamide (PAM) were used to treat coal samples to make wettability enhancement and medium wettability conversion, respectively. The contact angle, surface tension, solid surface energy, infrared spectroscopy, and high-pressure water injection desorption were performed to investigate the effects of reagents on the wettability alteration mechanism and desorption characteristics of coal. The results demonstrated that the surface energy, hydrogen bonds and oxygen-containing functional groups of coal alter wettability and gas desorption. The APG-treated coal samples exhibited increased surface energy, hydrogen bonds and oxygen-containing functional groups, whereas the PAM-treated coal samples demonstrated the opposite trend. The surface energy of coal reflects the state of APG and PAM molecules adsorbed on the coal surface, and the polar force of surface energy in coal follows a quadratic relationship with the volume of gas displacement desorption. Increasing the number of hydrogen bonds and oxygen-containing functional groups can improve wettability and decrease the interaction force between coal and methane molecules. This contributes to the lower atmospheric desorption of the APG-treated coal samples at high pressure. The total desorption volume of the APG-treated coal samples was 10–34% of that of the original coal at 0.737, 1.027, and 2.004 MPa gas pressures. The total desorption volume of PAM-treated samples at 2.004 MPa was 2.3474 cm3/g, which exceeded that of the original coal. Therefore, APG and PAM promoted gas desorption, and wettability enhancement yielded better results. This study provides an experimental approach for selecting the best reagent and excellent guidance for field applications.

A critical review of carbonate reservoir wettability modification during low salinity waterflooding

The nature of carbonate reservoirs promotes the adsorption of oil onto the rock surface hence making oil recovery a challenge even with the interventions of varied chemical EOR methods. Recently, low salinity water flooding has become of great interest since it is cost-effective and environmentally friendly. Although low salinity waterflooding has been highly investigated in sandstone reservoirs, it is not the same for carbonate reservoirs due to its complexities. Nonetheless, it has been proposed as a favourable technique to mobilise the trapped oil in carbonate reservoirs. Wettability alteration is regarded as the most accepted mechanism for low salinity flooding but has not been well understood making field scale applications doubtful. In this paper, we present a detailed review of the wettability alteration mechanisms in carbonate reservoirs during low salinity waterflooding. Parameters influencing wettability alteration in carbonates and the interactions that occur at the rock/brine/oil interface are also presented. The different methods utilised for wettability measurements during low salinity waterflooding are also reviewed including their drawbacks and advantages and recommendations. This will provide an improved understanding of the low salinity flooding application in carbonate reservoirs.

Experimental Study on the Influence of Wettability Alteration on Gas–Water Two-Phase Flow and Coalbed Methane Production

The surface wettability is important in the change in the relative permeability of gas and water. Due to the heterogeneous property of coal, it has a mixed wetting state, which makes it difficult to predict the change in permeability. To investigate the influence of different wettabilities on two-phase flow, a total of three different rank coal samples were collected and were treated with different chemicals. The alteration of the coal’s wettability, characteristics of gas–water flow, and relative permeability of the coal after the chemical treatments were analyzed. The research conclusions suggest that (1) the coal samples treated with SiO2 and H2O2 increased the hydrophilicity of the coal surface, while the coal samples treated with DTAB increased the hydrophobicity of the coal surface. Compared to SiO2, both H2O2 and DTAB can form a uniform wetting surface. (2) The wettability alteration mechanism among the three different chemical reagents is different. (3) All the chemicals can change the gas–water interface. The water migrates more easily through the cleats after H2O2 treatment, while it is more difficult for the water to migrate through cleats after the DTAB treatment. (4) There are two types of flow states of gas and water on different wetting surfaces. A slug flow is formed on a hydrophilic surface, while an annular flow is formed on a hydrophobic surface. (5) The crossover point and the residual water saturation of the relative permeability curves were influenced by the surface wettability.

Synthesis and application of polyacrylamide grafted GO and MWCNT nanocomposites for enhanced oil recovery: a coreflooding study

Most of the oil reserves have remained unrecovered during primary and secondary recovery scenarios which raise the need for novel and more useful recovery methods to produce the unrecovered oil and increase the recovery factor as an Enhanced oil recovery method. As the most common oil recovery method, the performance of the water injection can be further enhanced by adding polymers to water by the mobility control mechanism. Nanoparticle and nanohybrid flooding are one of those novel methods which can recover oil using wettability alteration and IFT reduction mechanisms. In this study, we synthesized polyacrylamide-based nanohybrids such as graphene oxide (GO)/PAM and carbon nanotube (CNT)/PAM combine the advantages of both nanoparticle and polymer flooding using a novel and simple method. The effect of different mechanisms involved such as wettability alteration, IFT reduction, and mobility control were studied separately in form of contact angle, IFT, and viscosity measurements and in combination with each other in the form of coreflooding tests were studied. The stability of the synthesized nanohybrids against temperature and salinity was investigated using TGA and bulk tests. The effectiveness of these novel nanohybrids was never investigated to this extent. Our investigation showed that GO/PAM nanohybrids had better performance in IFT reduction and mobility control and CNT/PAM in wettability alteration. During coreflooding tests, the GO/PAM showed the highest light and heavy oil recoveries with recovering 63.8% and 28.57%, respectively, in comparison to CNT/PAM with recovery factors of 60.95% and 25.71%. Both of the nanohybrids showed great performance in oil recovery due to wettability alteration and IFT reduction but the GO/PAM showed the best performance because of its higher viscosity which made the mobility control of the injected fluid much better.

Synergistic study of xanthan-gum based nano-composite on PELS anionic surfactant performance, and mechanism in porous media: Microfluidic & carbonate system

Rising global energy demand and decrease in world fossil fuels reserves draw attention toward production from trapped oil in the reservoirs. CEOR methods are proved and efficient methods which can be applied for increased oil recovery. In this research, the EOR potential of a novel nanocomposite and a developed surfactant was evaluated in the presence of various ions and the production enhancement mechanisms were studied using glass micromodel. Primary, the synergistic effect of the nanocomposite and the natural surfactant on Interfacial tension (IFT) reduction and wettability alteration was studied. After quantitative analysis and investigation of the various mechanisms, it was understood that the presence of the nanocomposite in the surfactant solution alters the wettability of an oil-wet carbonate surface to a water-wet one. Adding nano-composite to surfactant solution can improve the wettability alteration ability of the surfactant up to 60.02%. The adsorption tests revealed that combining the nanocomposite with surfactant solution can reduce surfactant adsorption by 18.99 %. The Zeta potential test was utilized to evaluate the stability of the solution. The zeta potential of the nano/surfactant solution was equal to −28 which illustrated a stable solution. In addition, the zeta potential measurements demonstrated the wettability alteration mechanism. After investigating the properties of the nano-surfactant solutions in the presence of different ions, optimum concentrations were determined and the mechanisms of the nano-chemical EOR method were visually investigated by injecting the desired solutions into the glass micromodel. Eventually, five different injection scenarios were designed for the core flood tests to evaluate the performance of each solution in the porous medium. The achieved final recovery for PELS, PELS/NaCl, and PELS/NaCl/NC solutions were 48.05%, 55.62%, and 60.38%, respectively and the Alternative injection scenario was the best injection plan.

Impact of surface roughness, surface charge, and temperature on sandstone wettability alteration by nanoparticles

The wettability of rocks affects the balance between capillary and viscous forces during multiphase flow through porous media, which in turn determines the fluid displacement process governing the recovery of oil from subsurface formations. In this work, the mechanism of wettability reversal of aged synthetic sandstones by metal oxide nanoparticles (SiO2 and Al2O3) was investigated with particular focus on the impact of surface roughness, zeta potential, and temperature. The synthetic surfaces were prepared from powders of Berea sandstone with known grain size ranges and their average roughness and roughness ratio were obtained from the 3D surface reconstruction of their microscope images. Each surface was subsequently aged in Permian crude oil to alter its wettability. For surfaces with larger grain sizes and lower surface roughness ratios, the lower capillary pressure allowed stronger oil/surface interactions, leading to enhanced oil-wetness. The wettability alteration effects of nanoparticles were then examined through real-time top view imaging and dynamic front view contact angle experiments. The negatively charged SiO2 nanoparticles rapidly reversed the sandstone wettability, indicating their potential applicability as wettability alteration agents. By contrast, the positively charged Al2O3 counterpart caused no wettability reversal. The mechanism of wettability alteration was further studied by microscale interaction analyses and nanoscale transmission electron microscopy. Because nanoparticles were only a few nanometers large, the microscale roughness had a negligible effect on the wettability reversal. Instead, the combined effect of van der Waals dispersion forces and surface-charge-induced electrostatic forces were recognized as the two key factors affecting the wettability of sandstone particles. Such interactions may be curbed at elevated temperatures due to a decrease in the zeta potential and colloidal stability of the particles.

A Review of Wettability Alteration by Spontaneous Imbibition Using Low-Salinity Water in Naturally Fractured Reservoirs

Analysis of fluid flow in naturally fractured reservoirs (NFRs), as a highly heterogeneous and complex system, requires a detailed study of the fracture-matrix interactions. The main process of fluid movement between the fracture and matrix is spontaneous imbibition (SI), which can occur in co/countercurrent fluid flow states. In addition, most carbonate rocks are fractured and non-water-wet, which can lead to low oil recovery. Wettability greatly affects the performance of the SI process. Injection of water or chemicals can be insufficient because fluids mostly pass through highly permeable fractures and lead to early breakthrough. Therefore, the wettability alteration mechanism should be applied in NFRs, and low-salinity water (LSW) injection is considered an effective enhanced oil recovery (EOR) approach. In this review, experimental and numerical studies of co/counter-imbibition are analyzed to show the importance of investigating the fracture-matrix interactions. In addition, the review shows the wettability effect on imbibition in fractured rocks. The review of experimental studies of LSW imbibition in fractured carbonates shows the possibilities for implementing an EOR method. However, the wettability alteration process during SI using LSW has not yet been studied, and no simulation models of co/countercurrent flows have yet been provided. Based on this review, more experimental studies are recommended to duplicate co/countercurrent imbibition using LSW. Advanced techniques such as CT scanning, MRI, and NTI can be used to reveal fluid distribution. Using experimental data, numerical models can be developed to characterize dynamic wettability alteration during co/countercurrent imbibition.

Digital rock workflow to calculate wettability distribution in a reservoir rock

Wettability has a strong influence on multi-phase flow behavior through reservoir rock. Reservoir rocks tend to have spatially varying wettability. Prior to contact with oil, rocks are almost always naturally water-wet. As oil invades the pore-space over geologic time, the initial water-wet state may be altered in certain locations due to adhesion of substances within the oil phase to the grains. Mechanisms of wettability alteration depend on various properties such as pressure, temperature, mineral chemistry, surface roughness and fluid composition. In this study wettability alteration in a reservoir rock is studied through direct simulation using multiphase Lattice Boltzmann method where the computational grid is constructed from segmented micro-CT images of the rock sample. The pore-grain interface is defined by a triangulated surface mesh for accurate fluxes near boundary and local curvature calculation. A capillary pressure drainage simulation is conducted in a water-wet Berea sandstone sample initially filled with water. When oil invades the pore space as the capillary pressure is increased, a fraction of the pore-grain surface is altered towards an oil-wet condition, as determined by a novel wettability alteration process. This process calculates local curvature at every surface element of the rock, obtains local capillary pressure from the simulation and assumes a disjoining pressure to determine water-film breakage at every location of the pore-grain surface. As a result, a spatially varying rock wettability is created. Using this new wettability distribution, the simulation is continued to allow the fluid phases to redistribute accordingly. The process is iteratively carried out until both fluid saturation and wettability distribution converged at a given applied capillary pressure. Afterwards, the pressure is ramped up to the next stage and the process is repeated again. It has been found that the wettability alteration is a slow dynamic process where the non-wetting phase can gradually invade finer pore space as the surrounding grain wettability is altered. In this study, it has also been found that wettability alteration of the reservoir rock produces lower connate water saturation during primary drainage compared to the simulation results without alteration. The resulting spatially varying wettability distribution from primary drainage is used for a subsequent water flooding simulation to calculate water-oil relative permeability curves. The methodology presented in this work can be leveraged to better understand and predict an improved mixed wetting conditions found in the reservoir rocks which is needed for more accurate displacement tests such as relative permeability simulations.

Spontaneous Imbibition Oil Recovery by Natural Surfactant/Nanofluid: An Experimental and Theoretical Study.

Organic surfactants have been utilized with different nanoparticles in enhanced oil recovery (EOR) operations due to the synergic mechanisms of nanofluid stabilization, wettability alteration, and oil-water interfacial tension reduction. However, investment and environmental issues are the main concerns to make the operation more practical. The present study introduces a natural and cost-effective surfactant named Azarboo for modifying the surface traits of silica nanoparticles for more efficient EOR. Surface-modified nanoparticles were synthesized by conjugating negatively charged Azarboo surfactant on positively charged amino-treated silica nanoparticles. The effect of the hybrid application of the natural surfactant and amine-modified silica nanoparticles was investigated by analysis of wettability alteration. Amine-surfactant-functionalized silica nanoparticles were found to be more effective than typical nanoparticles. Amott cell experiments showed maximum imbibition oil recovery after nine days of treatment with amine-surfactant-modified nanoparticles and fifteen days of treatment with amine-modified nanoparticles. This finding confirmed the superior potential of amine-surfactant-modified silica nanoparticles compared to amine-modified silica nanoparticles. Modeling showed that amine surfactant-treated SiO2 could change wettability from strongly oil-wet to almost strongly water-wet. In the case of amine-treated silica nanoparticles, a strongly water-wet condition was not achieved. Oil displacement experiments confirmed the better performance of amine-surfactant-treated SiO2 nanoparticles compared to amine-treated SiO2 by improving oil recovery by 15%. Overall, a synergistic effect between Azarboo surfactant and amine-modified silica nanoparticles led to wettability alteration and higher oil recovery.

Modelling of carbonate rock wettability based on surface charge and calcite dissolution

The lack of consensus on the mechanisms underpinning low salinity waterflooding (LSWF) oil recovery has affected the successful implementation of LSWF in carbonate reservoirs. Many investigators link the improved oil recovery observed from LSWF to wettability alteration. Several models are proposed in the literature to study the wettability alteration mechanism. However, the reliability of some of the models is being contested, as they struggle to accurately predict the oil recovery trend. This study aims to develop a new wettability alteration model that can predict the performance of LSWF oil recovery processes. We propose a new wettability indicator (WI) that integrates three mechanisms (surface charge alteration/ζ-potential, calcite dissolution, and ion exchange) which, are suggested, dictate LSWF wettability alteration. The model was implemented in UTCHEM, which was coupled with PHREEQCRM, and was used to simulate several experimental LSWF oil recoveries.The results produced from the simulations with the new model are consistent with experimental data. The outcomes from this study show that adsorption of crude oil is still possible even when the oil-brine and the rock-brine interfaces have the same polarities of ζ-potentials. The results further demonstrate that the improved oil recovery observed in LSWF is not always caused by the wettability alteration, but also caused by other factors such as rock quality and physical displacement. The outcome of the study also indicate that early injection of the low salinity brine can significantly improve the oil recovery.Findings from this study can improve the understanding of the LSWF process. Moreover, the model proposed in this study can be applied in the design and planning of LSWF projects to estimate the performance of the LSWF.

Application of hybrid low salinity hot water flooding to enhance oil recovery from heavy oil carbonates

The high efficiency of Low Salinity Water (LSW) injection in carbonates, leading to rock wettability alteration from oil-wet to water-wet and, hence, resulting in better oil displacement, has been confirmed by numerous studies. In recent years, the combination of LSW injection with other Enhanced Oil Recovery (EOR) techniques has been widely discussed, to activate the synergistic effects of hybrid EOR methods leading to additional oil recovery. The idea of combining LSW injection with a thermal approach, known as Low Salinity Hot Water (LSHW) injection, is a highly promising hybrid EOR method for heavy oil carbonate formations. In this study, the performance of LSW and hybrid LSHW injection was experimentally evaluated for heavy oil carbonate cores by different measurements of rock-fluid interactions and core flooding experiments. Contact angle measurements were conducted to investigate the optimal dilution of seawater (SW) and evaluate the performance of different variations of Potential Determining Ions (PDIs) concentration on wettability change. Appropriate dilution and ion management was applied to design LSW and engineered water (EW) for oil displacement at different temperatures (from 20 to 70 °C) in order to evaluate the standalone LSW and hybrid LSHW injection performance. The injection of LSW and EW was estimated to be inefficient for heavy oil carbonates, while hybrid LSHW flooding showed a significant increase of oil recovery with the best performance of the brine spiked by PDIs, where 60% and 55% of the residual oil was displaced at 50 °C and 70 °C, respectively. Moreover, the injection of LSHW directly after SW was found to be more practical than following LSW flooding. The application of the hybrid EOR method activates different mechanisms, such as oil detachment from the rock surface, due to the wettability alteration by EW/LSW and viscosity reduction by the thermal methods. Combined active mechanisms result in better performance, compared to the standalone EOR methods. Rock dissolution and multi-ion exchange by PDIs were identified as the main mechanisms of wettability alteration by EW/LSW via the results of ion chromatography analyses. The synergy between EOR methods affects the active mechanisms of LSW/EW flooding. For example, an increase in temperature showed more active multi-ion exchange and rock dissolution, which resulted in higher oil release from the rock surface.

Microfluidics-Based Low Salinity Wettability Alteration Study of Naphthenic-Acid-Adsorbed Calcite Surfaces

Microfluidics is relatively a new area in the oil and gas industry and has great potential to be used as an effective tool to address various outstanding research questions where microscale investigation is necessary. Low salinity brine flooding has been known to enhance oil recovery in carbonate reservoirs through a wettability alteration mechanism. Wettability alteration is a molecular-scale phenomenon that is often characterized at a mesoscale through contact angle experiments. By using microfluidic chips, the low salinity effects involving solid–fluid interactions could be directly visualized, and the wettability alteration could be verified at microscale. However, to replicate solid–fluid interactions involved in carbonate reservoirs, the internal wetting surfaces must be transformed to carbonate surfaces. In this study, first, wetting surfaces of straight-channel glass microfluidic chips were functionalized using a metal-chelating silane coupling agent, and then, the surfaces were coated with CaCO3 using a layer-by-layer (LbL) deposition process. The calcite-coated straight-channel glass microfluidic chips were then used to investigate the effects of brine salinity and the role of divalent ions in the wettability alteration of oil-wet calcite surfaces at both room temperature and high temperature (70 °C). Naphthenic acid was used as the surface-active component in a model oil to render calcite surfaces oil wet. Six single-electrolyte-based brines were used in this study: high salinity 5 M NaCl, seawater equivalent 0.656 M NaCl, and 4-times diluted seawater-equivalent low salinity brines─0.164 M ionic strength NaCl, Na2SO4, MgSO4, and MgCl2. The low salinity brines were found to induce significant wettability alteration on naphthenic-acid-adsorbed calcite surfaces at ambient temperature. Low salinity Na2SO4 resulted in the highest wettability alteration followed by low salinity NaCl solution. Insignificant wettability alteration was observed in 0.656 M NaCl compared to 0.164 M NaCl where the wettability alteration was significant, suggesting the extent of wettability alteration increases with reduction in brine salinity. Magnesium ions were found to be unfavorable for wettability alteration in the presence or absence of sulfate ions. Exposure to higher temperature resulted in no or insignificant further wettability alteration in most of the brines.

Visual investigation of the effect of clay-induced fluid flow diversion on oil recovery, as a low-salinity water flooding mechanism

Low-salinity water flooding (LSWF) is an EOR method applicable to both sandstone and carbonate reservoirs. In recent years, LSWF has become an attractive technique but still some uncertainties concerning the governing mechanisms exist in studies. Mechanisms such as wettability alteration, osmosis, and fluid flow diversion by fines migration are proposed to explain the incremental oil recovery by LSWF in sandstones. Flow diversion is still being debated as to whether this mechanism works and, if it does, to what extent. This mechanism occurs due to clay swelling and fines migration, which results in pores blockage, diversion of the fluid flow to unswept areas, and enhanced oil displacement. Hence, the presence of clays is claimed to be a necessity for the success of LSWF in sandstone reservoirs. Here we proposed a new approach to study effects of different mechanisms of LSWF alone and in combination of each other using micromodels to track fluid flow diversion and the reason behind it and its subsequent benefits in case of oil recovery, visually. In this paper micromodel tests in different wetting and clay presence conditions were designed and conducted to investigate the standalone fluid flow diversion mechanism and the combination of it with wettability alteration and osmosis effects during LSWF. Tests conducted in water wet and oil wet states showed that the presence of clays is not the main criterion for activating the LSWF effect and the initial wettability is more critical. Our studies showed that the fluid flow diversion share in oil recovery is only 30% of the total incremental oil displaced by LSWF, while about 70% of the oil is produced by wettability alteration and osmosis mechanisms. It is reasonable to say that, although flow diversion is an active mechanism, it is not the dominant one and on the other hand wettability alteration is.

Screening of Surfactants for Flooding at High-Mineralization Conditions: Two Production Zones of Carbonate Reservoir

The selection of effective surfactants potentially can mobilize oil up to 50% of residuals in mature carbonate oilfields. Surfactants’ screening for such oilfields usually is complicated by the high salinity of water, high lipophilicity of the rock surface, and the heterogeneous structure. A consideration of features of the oilfield properties, as well as separate production zones, can increase the deep insight of surfactants’ influence and increase the effectiveness of surfactant flooding. This article is devoted to the screening of surfactants for two production zones (Bashkirian and Vereian) of the Ivinskoe carbonate oilfield with high water salinity and heterogeneity. The standard core study of both production zones revealed no significant differences in permeability and porosity. On the other hand, an X-ray study of core samples showed differences in their structure and the presence of microporosity in the Bashkirian stage. The effectiveness of four different types of surfactants and surfactant blends were evaluated for both production zones by two different oil displacement mechanisms: spontaneous imbibition and filtration experiments. Results showed the higher effect of surfactants on wettability alteration and imbibition mechanisms for the Bashkirian cores with microporosity and a higher oil displacement factor in the flooding experiments for the Vereian homogeneous cores with lower oil viscosity.

Characterization of Ultrasonic-Induced Wettability Alteration under Subsurface Conditions.

Understanding and manipulating wettability alterations has tremendous implications in theoretical research and industrial applications. This study proposes a novel idea of applying ultrasonic for wettability alterations and also provides its quantitative characterizations and in-depth analyses. More specifically, with pretreatment of ultrasonic, mechanisms of wettability alteration were characterized from the contact angle measurements, as well as the in-depth analyses from atomic force microscopy (AFM), X-ray diffraction (XRD), and Fourier-transform infrared spectroscopy (FTIR). After ultrasonic treatments, the wettability of mineral with low permeability is determined to altered from strong hydrophilic to intermediate wettability. The mechanism interpretations are conducted by means of the AFM, XRD, and FTIR. Basically, as the time of ultrasonic treatment increases, the AFM results indicate that the roughness of rock surface and oil/rock interface (contact area) with surroundings of brine is enhanced. Meanwhile, the XRD results show the diffusions of clays from the rock surface to the aqueous phase, and FTIR indicates that the number of functional groups of Si-O-Si, C-O-C, C-O, C═O, and OH decreases while the number of COOH and C═C═O groups increases. This study clearly reveals the surface chemistry of oil-rock wettability alteration in the subsurface conditions, which would provide technical support for subsurface usage of geo-energy productions and carbon sequestrations.

Oil-water interfacial tension, wettability alteration and foaming studies of natural surfactant extracted from Vernonia Amygdalina

Surfactant flooding is an enhanced oil recovery (EOR) method for recovering residual oil in the reservoir through mechanism of interfacial tension (IFT) reduction and wettability alteration. Due to toxicity and high cost associated with conventional surfactants, recent research has focussed on developing low-cost and environmentally benign surfactants. Herein, a low-cost green surfactant is extracted from Vernonia Amygdalina (VA) and appraised for EOR applications. The extracted surfactant was characterized using Fourier Transform Infrared (FTIR) and High-Pressure Liquid Chromatography (HPLC). The IFT of the synthesized surfactant at the oil-water interface was determined using Kruss tensiometer. Additionally, the foam stability of the synthesized surfactant was examined. Moreover, the wettability of the saponin based natural surfactant (SBNS) at the rock-fluid interface was analysed using Dataphysics drop shape analyser. Experimental result revealed that SBNS (1 wt% concentration) stabilized foam for longer periods with half-life of 1100 min. Furthermore, the synthesized surfactant was effective in lowering the IFT of oil-water interface from 18 mN/m to 0.97 mN/m. Finally, SBNS altered the wettability of sandstone cores to water-wetting condition by reducing the contact angle from 118.5 ° to 45.7 °. Overall, SBNS exhibit excellent properties desirable for EOR and thereby recommended as supplementary alternative to conventional surfactants.