Water-wet Conditions Research Articles

A micromodel investigation on the flooding of glycolipid biosurfactants for enhanced oil recovery

Biosurfactants can enhance oil recovery by decreasing the interfacial tension between water and oil, and altering the rock's wettability. In this study, the effect of two low molecular-weight glycolipid biosurfactants (rhamnolipid and sophorolipid) on enhancing oil recovery was investigated. The biosurfactants were economically produced from waste sunflower oil. The qualitative oil dispersion experiments were used to evaluate the biosurfactants’ ability to separate oil, Surface tension and interfacial tension tests were carried out at various salinity rates. The potential of rhamnolipid and sophorolipid solutions to alter carbonate rock from an oil-wet state to a water-wet state was studied using the wettability test by measuring the contact angle. Moreover, the effect of rhamnolipid and sophorolipid biosurfactants on breaking the emulsion and improving the sweeping efficiency in porous media was investigated and compared using the micromodel test. Then three distinct homogeneous, heterogeneous, and layered patterns were created and tested in order to completely investigate the difference in oil displacement mechanism in three micromodels, and the impacts of the biosurfactant injection zone's permeability on oil recovery to design injection well patterns. The test results showed that these two biosurfactants were effective at separating crude oil from water. It was further observed that the rhamnolipid solution at 1000 ppm concentration and 60,000 ppm salinity reduced the interfacial tension to 5.42 mN/m, and the sophorolipid solution at 5000 ppm concentration and 80,000 ppm salinity reduced it to 7.93 mN/m. The rhamnolipid solution increased the contact angle between the oil drop and the carbonate rock from 41.42° to 109.26°, and the sophorolipid solution increased it from 32.16° to 104.12°. Also, the micromodel flooding test confirmed that in the case of rhamnolipid solution at the optimal concentration and salinity, the amount of oil recovery was measured as 80, 70, and 74% in the homogeneous, heterogeneous, and layered micromodels, respectively, while for the sophorolipid solution at the optimal concentration and salinity, it was recorded as 71, 61, and 69%, respectively. The micromodel results did not prove the fingering phenomenon under injection of either rhamnolipid or sophorolipid. Furthermore, proper distribution and breaking of the emulsion into micron size were confirmed. Accordingly, one can conclude that both surfactants (rhamnolipid and sophorolipid) have the potential to be utilized in oil field operations.

Experimental investigation of wettability alteration of oil-wet carbonate surfaces using engineered polymer solutions: The effect of potential determining ions ([Mg2+/ SO42−], and [Ca2+/ SO42−] ratios)

Engineered water polymer flooding (EWPF) is a promising method to improve oil recovery in carbonate reservoirs holding more than half of the world's oil reserves. It involves combining engineered water (EW) and polymer flooding (PF) to modify rock wettability, reduce mobility ratio, promote polymer stability, and lower required polymer concentration. However, limited studies addressed the simultaneous effect of engineered water compositions (i.e. potential determining ions (PDIs)) on the viscosity of polymer and wettability alteration of various carbonate surfaces. Accordingly, this study aimed to investigate the effect of salinity, PDIs, and polymer functional groups (partially hydrolyzed polyacrylamide (HPAM), and acrylamide tertiary butyl sulfonic acid (ATBs)) on the wetting properties of calcite, chalk, and dolomite surfaces as well as the viscosity of solutions at static conditions. The experimental protocol included viscosity, contact angle (CA), pH, and static adsorption tests. Two combinations of PDIs were considered in the study: [Mg2+/SO42−], and [Ca2+/SO42−]. The results revealed that the polymer becomes more tolerant to the salinity as the sulfonation degree increases, given the same molecular weight. However, at a polymer concentration of 5000 ppm, the HPAM polymer showed higher viscosity than the ATBs-based polymers, as the formation brine (FB) was diluted to 100 folds (100DFB). The tendency of shifting the wettability of carbonate surfaces towards a more water-wet state using EW and EWP treatment solutions decreased in the following order: Chalk ≥ Calcite˃ Dolomite. The study also indicates that, the wettability alteration towards favorable condition is dependent on the initial wettability of the carbonate surface. The higher level of oil-wetness detected in aged dolomite, compared with calcite and chalk, resulted in less effectiveness of EWP for dolomites. However, the low polymer interaction with dolomite surfaces indicates a positive impact on reducing polymer consumption. Moreover, the HPAM polymer was more effective in altering the wettability of dolomite towards a water-wet state compared to the ATBs-based polymer. The overall results indicate that ATBs-based polymer is a potential candidate for optimizing the effectiveness of EWPF in carbonates.

Wettability Alteration of Limestone Carbonate Cores Using Methylene Blue and Alumina-Based Nanofluid: Implications for EOR

Wettability is a key parameter for optimizing the residual oil recovery from geological rock formations and it provides a path for improved oil recovery and geo-storage of energy. Thus, the key motive behind wettability alteration from hydrophobic to hydrophilic is to enhance the oil productivity. Thus, this work concentrates on Sui main limestone reservoir core samples’ wettability alteration (altering their surface wetting behavior from an oil-wet to water-wet state) for enhanced oil recovery. Hence, we examine the effectiveness of alumina nanofluid as well as a new chemical methyl blue to alter the wettability. Methyl blue is released on a large scale from various industries, i.e., pharma, textile, and food industries, which is a key environmental concern; subsequently, it contaminates the water table. Hence, the study explores the effects of MB and alumina nanofluid on wettability. The effect of nanofluids formulated via dispersing the alumina nanoparticles in aqueous solutions at various concentrations (0. 0.05, 0.3, 0.50, 0.75, and 1.0 wt. %) were tested for wettability modifications under different physio-thermal conditions. Subsequently, the wettability change was examined for these samples treated with different concentrations of MB (10, 15, 30, 50, and 100 mg/L) for 7 days at two different temperatures (25 and 50 °C). The results show that the hydrophobicity of the SML carbonate rock significantly reverses while treating with alumina nanofluids and MB. Thus, the wettability modification/reversal via the treatment of MB and alumina nanofluids can be an effective mechanism for hydrogen injections and EOR processes.

Experimental investigation of wettability alteration, IFT reduction, and injection schemes during surfactant/smart water flooding for EOR application

In recent years, the application of smart water and surfactant in order to improve oil recovery has attracted special attention in carbonate reservoirs. In this research, the effects of various salts in smart water and two surfactants of Cetyl Trimethyl Ammonium Bromide (CTAB) and Sodium Dodecyl Sulfate (SDS) on the wettability alteration of carbonate rock and IFT were studied. Besides, along with micromodel flooding, core flooding tests were conducted to assess the amount of oil recovery at reservoir conditions as an injection scheme was used. In this regard, the results illustrated that the presence of CTAB or SDS in seawater (SW) can act better in contact angle reduction compared to smart water. Also, a four times increase in the concentration of SO42− and removing Na+ from SW reduced the contact angle to 68° and 71°, respectively, being the best possible options to alter the carbonate surface wettability to more water-wet states. Moreover, in the second-order process in which the rock section was first placed in SW, and then was put in the smart solution (with or without surfactant), CTAB had a great effect on the wettability alteration. In the case of IFT reduction, although SW4Mg2+, compared to other ions, better decreased the IFT to 17.83 mN/m, SW + SDS and SW + CTAB further declined the IFT to 0.67 and 0.33 mN/m, respectively. Concerning different ions, divalent cations (Mg2+ and Ca2+) show better results in improving oil recovery factor. However, the combination of SW and surfactants has a more positive effect on boosting oil recovery, as compared to smart water flooding. It should be mentioned that the first-order injection is better than the second-order one since SW is flooded at first, and then, after the breakthrough, smart water is injected into the micromodel. In addition, the core flooding tests showed that SW + CTAB and SW + SDS in tertiary injection increased the oil recovery to about 59 and 57%, respectively, indicating that the presence of CTAB could be more effective than that of SDS.

Novel fluid typing method of NMR dual-TW logging in mixed-wet reservoirs

In mixed wetting reservoirs, the fluids typing is difficult by using nuclear magnetic resonance (NMR) logging. The data processing and interpretation method of NMR dual-waiting time (TW) activation faces serious challenges and the previous NMR time-domain analysis (TDA) of NMR dual-TW logging for water-wet condition is not applicable. The petrophysical characteristics under mixed-wet conditions was studied and the oil-wet factor was defined, and new NMR logging response equations was investigated and the echo train difference between long and short wait times were derived. The relaxation parameters of fluids and water saturation was finally calculated by the genetic algorithm. Therefore, a new improved TDA method was proposed for mixed-wet reservoirs. To verify the method, a petrophysical model was set and some simulations proved it accurate. A case study from Chang 8, Ordos Basin, China, was studied, and the oil saturation and volume in the flushed zone were calculated. From the oil-testing results, two cross-plots for fluid typing were constructed based on the calculated oil saturation in flushed zone, T2 geomean difference of dual-TW NMR logging. The practical application shows that the novel TDA method of NMR dual-TW logging for mixed-wet reservoirs is efficient for the fluid identification.

Simulation of nuclear magnetic resonance response based on 3D CT images of sandstone core

In recent years, nuclear magnetic resonance (NMR) logging has become increasingly prevalent in the characterization of rock properties such as porosity, permeability, saturation, and pore size distribution. However, interpreting such properties accurately from NMR logging data is challenging for some reservoirs. In particular, the impact of salinity, viscosity, and saturation on NMR measurements is not always clear, which can lead to inaccuracies in the resulting data interpretation. Properly accounting for these factors is essential in order to obtain accurate and reliable measurements for effective characterization of subsurface formations. This study utilized a random walk technique to simulate the NMR response of homogeneous sandstones using 3D CT images and conducted a sensitivity analysis under various salinity, crude oil viscosity, and water saturation conditions. The results indicate that the T2 relaxation time slightly shifts toward the short relaxation direction as the salinity of the formation water increases. In addition, longer echo intervals result in a more significant forward shift in the T2 value than shorter intervals. Whereas, for crude oil, the T2 relaxation time becomes shorter as its viscosity increases. Furthermore, the effect of echo interval on the forward T2 shift is less pronounced for crude oil than it is for formation water. Under water wet conditions, the T2 spectrum of crude oil exhibits a peak at the volume relaxation position. As the water saturation decreases, the left two peaks in the T2 spectrum shift toward shorter relaxation times. Under oil wet conditions, the T2 spectrum exhibits a complex three-peak structure. The method provides a physical basis for interpreting NMR macroscopic responses, and the simulated NMR responses can help identify fluids in reservoirs.

Influence of Rock Firing on the Wettability of Clay-Rich Sandstones

Rock firing is a conventional technique of core preparation to prevent clay swelling and fines migration in clay-rich rock; however, the influence of rock firing on the wetting behaviors and alterations of mineralogical compositions of clay-rich sandstones is not yet explicit. Thus, we assessed and compared the impacts of rock burning at two different temperatures (700 and 1100 °C) on the changes in wetting states of Bentheimer (BN) and clay-rich Bandera Gray (BG) sandstones through contact angle measurement, Amott wettability index determination, and thermogravimetric analysis (TGA). Results showed that rock firing makes the rocks more water-wet, but the clay-rich BG sandstone becomes significantly more water-wet than the quartz-dominated BN rock with increasing temperature. There was no change in rock porosity due to firing, but some clay remained, whereas some clays were transformed into other minerals after rock firing. Particularly, there were thermal transformations of clay to quartz and the disappearance of dolomite, chlorite, and clinochlore. Such transformation of these minerals into alkali metal oxide silicates dispersed on the rock matrix makes the surface more polar and enhances the interactions with water molecules, resulting in more water wettability for the BG sandstone. The study suggests that rock firing could change the clay-rich rock-wetting state into a more water-wet condition than the clay-poor or zero-clay sandstone samples; thus, the influence of rock burning on rock-wetting behavior should be considered to ensure an accurate prediction of the rock-wetting state due to rock burning. Moreover, burning at 1100 °C is recommended to achieve effective clay transformation and removal in clay-rich rock to prevent swelling, fines migration, and clay–fluid interactions.

Host-rock and caprock wettability during hydrogen drainage: Implications of hydrogen subsurface storage

Underground hydrogen storage (UHS) is an integral part of H2 economy value chain, essential for industrial-scale actualization of global decarbonization objectives. UHS in depleted hydrocarbon reservoirs is considered a safer and promising storage technique due to presence of large porous formation and impermeable seal, but its effectiveness depends on precise estimation of rock wettability, a crucial parameter in reservoir characterization, which controls pore-scale gas distribution, H2 containment safety and withdrawal efficiency. Several recent studies have provided contact angles data for host rock-water-H2 (quartz and sandstone) and caprock-water-H2 (mica and shale) measured through sessile drop method. However, the contact angle datasets for carbonate rock-water-H2 measured via captive bubble method, which can reflect the wettability of the rock during imbibition and drainage are largely unknown. The present work characterized the wettability of carbonate-water-H2 systems for various rock types, prepared from five different lithologies with different mineral assemblages. The contact angle θ was measured using the captive bubble method at two different temperatures of 303 K and 348 K, and three different pressures (3.44, 10.34, and 17.23 MPa). Experimental results showed that all rocks remained intrinsically strongly water-wet (θ ranged between 17° – 30°) at all experimental conditions. Furthermore, no significant change in contact angles occurred with changing temperature and pressure. For instance, at 17.23 MPa, contact angle of H2/brine on anhydrite (S-4) rock were measured as 19° and 20° at 303 K and 348 K respectively, suggesting that H2 remains the non-wetting phase with increasing storage depth and at warmer reservoirs. The study suggests that the pore-scale flow and fluid connectivity of H2 may not be influenced by changing wettability in pure storage rocks/caprocks. Thus, the wettability of carbonates storage rocks and caprocks may not be over-predicted by assuming strongly water-wet conditions for the non-contaminated rock surfaces during UHS.

Rock wettability and interfacial tension improvement by exposure time effect in modified water injection process coupled with silica nanoparticles

New approaches to low salinity water (LSW) injection methods, such as LSW/surfactant, LSW/polymer, and LSW/nanofluid flooding, have been studied for oil reservoirs. Numerous researchers discussed the mechanisms related to enhanced oil recovery (EOR) efficiency and highlighted the significant impact of the wettability alteration and interfacial tension (IFT) reduction. This work studied the effect of exposure time on the wettability alteration and IFT in the LSW/nanoparticle (LSWN) flooding. Contact angle tests investigated rock wettability over a series of different times. A pendant drop tensiometer was used to measure the IFT. By coreflood apparatus, waterflood tests were also conducted, considering the effect of soaking time. Laboratory results showed that the involved mechanisms are time-dependent. More water-wet conditions and higher oil recovery were obtained under longer soaking time. In addition, the positive effect of LSWN was observed in tertiary flooding tests. The results also indicate that the effect of water-soluble oil compounds should be considered in measuring wettability and IFT.

Investigation on the interactions of resinous and asphaltenic synthetic oils and silicon oxide nanoparticles stabilized by different ionic liquid-based surfactants: interfacial tension and wettability alteration studies

The effects of the main components of crude oil, especially resin and asphaltene fractions, are essential concerns for efficient enhanced oil recovery (EOR) processes, especially during chemical injection processes. This importance comes from the nature of these two fractions which can act as surface active agents with undeniable effects on the used chemical for interfacial tension (IFT) reduction and wettability alteration. In this way, the effect of silicon oxide nanoparticles (SiO2-NPs) concomitant with two ionic liquids (ILs), namely 1-dodecyl-3-methyl imidazolium chloride ([C12mim][Cl]) and 1-octadecyl-3-methyl imidazolium chloride ([C18mim][Cl]), is investigated on the wettability alteration and IFT reduction using synthetic oils prepared by dissolving the extracted resin and asphaltene fractions with a concentration of 1–5 wt%. The measurements reveal that the effect of resin fraction is less than the asphaltene fraction for IFT reduction and wettability alteration. The sole presence of resin fraction reduces the IFT from 35.3 to 28.3 mN/m as the concentration is increased from 1 to 5 wt%, while a similar increase in the asphaltene fraction concentration reduces the IFT from 35.5 to 19.1 mN/m. Besides, the results reveal that the presence of [C12mim][Cl] in the range of 0–1000 ppm leads to a reduction in IFT from its maximum value of 35.3 to 0.81 mN/m, while in the case of [C18mim][Cl] with similar concentration variation, IFT is reduced from 35.3 to 0.7 which means the better effect of IL with longer chain length on the IFT reduction. Further analysis revealed that the effect of asphaltene fraction on the IFT is higher than resin fraction since the minimum IFT value was observed for [C18mim][Cl] with the value of 0.58 mN/m, while the contact angle (CA) values revealed revers effect for asphaltene fraction compared with the resin fraction. In general, regardless of the used IL, it seems that ILs leading to better wettability conditions which are crucial for EOR purposes and even better IFT values that can mobilize the trapped oil toward production points. Besides, further measurements revealed a positive effect of SiO2-NPs concomitant with the ILs to move the wettability toward the strongly water-wet condition with CA values of 29.2° and 28.3° for SiO2-NPs concentration of 1000 ppm and 1000 ppm of concentration for [C12mim][Cl] and [C18mim][Cl], respectively, for resinous synthetic oil (RSO) (5 wt%) while no meaningful effect regarding the SiO2-NPs presence at the different concentrations (100–2000 ppm) is found on the IFT reduction. A similar trend is observed for asphaltenic synthetic oil (5 wt%)/aqueous solution (SiO2-NPs with a concentration of 1000 ppm + ILs with a concentration of 1000 ppm) which reduces the CA to 26.3° and 37.8° for [C12mim][Cl] and [C18mim][Cl]), respectively.

Investigation of the effect of diethylene triamine pentaacetic acid chelating agent as an enhanced oil recovery fluid on wettability alteration of sandstone rocks

This study used the diethylene triamine pentaacetic acid (DTPA)-seawater (SW) system to modify the sandstone rock wettability and enhance oil recovery. The investigation involved conducting wettability measurement, Zeta potential measurement, and spontaneous imbibition experiment. The introduction of 5% DTPA-SW solution resulted in a significant decrease in the rock-oil contact angle from 143° to 23°, along with a reduction in the Zeta potential from −2.29 mV to −13.06 mV, thereby altering the rock surface charge and shifting its wettability from an oil-wet state to a strongly water-wet state. The presence or absence of potential determining ions (Ca2+, Mg2+, SO42−) in the solution did not impact the effectiveness of DTPA in changing the rock wettability. However, by tripling the concentration of these ions in the solution, the performance of 5% DTPA-SW solution in changing wettability was impaired. Additionally, spontaneous imbibition tests demonstrated that the 5% DTPA-SW solution led to an increase in oil recovery up to 39.6%. Thus, the optimum mass fraction of DTPA for changing sandstone wettability was determined to be 5%.

Efficiency of the Green Surfactant Derived from Avena sativa Plant in the Presence of Different Salts for EOR Purposes

In this investigation, a unique approach using a green surfactant extracted from the Avena sativa (AS) plant in conjunction with three different salts, including Na2CO3, NaCl, and Na2SO4, was examined for enhanced oil recovery. In addition, the efficiency of NaOH as a supplementary chemical in the process was investigated. Based on the results of the interfacial tension (IFT), the optimum value of NaOH was found to be 2,000 ppm, while the green surfactant had a CMC value of 4,000 ppm. The IFT value at the CMC point of NaOH was 2.34 mN/m, when the FB was used, and the IFT value was 2.78 mN/m, when deionized water was used. In addition, in terms of IFT reduction, wettability modification, and oil recovery factor enhancement, Na2CO3 was the most suitable salt with the AS surfactant at the CMC point (4,000 ppm), followed by NaCl and then Na2SO4. The IFT values at the optimum salinity point (10,000 ppm) of Na2SO4, NaCl, and Na2CO3 were 3.18, 3.05, and 2.87 mN/m, respectively. Moreover, the contact angles at the optimum salinity point of 10,000 ppm after 150 hr and at the reservoir temperature (80°C) were 36.58°, 40.76°, and 44.18° with Na2CO3, NaCl, and Na2SO4, respectively. Furthermore, the addition of NaOH improved the efficiency of the green surfactant in terms of maximizing the recovery factor by decreasing the IFT values and changing the wettability of the rock toward a more water-wet state. The final recovery factors of 88.45%, 80.87%, and 7.98% were attained using Na2CO3, NaCl, and Na2SO4, respectively, when 1 PV of NaOH was injected as the preflush, followed by 4 PVs of natural AS surfactant.

Role of sulfate ion on wettability alteration and oil mobilization in chalk reservoirs during modified salinity waterflooding

It has often been reported that an increase in sulfate has a positive effect on altering wettability and mobilizing oil during modified salinity water flooding in carbonate reservoirs. However, this understanding is mostly based on experimental studies using outcrop rock material. Therefore, this study aims to reassess the role of sulfate on altering wettability and recovery performance during modified salinity water injection in oil-saturated porous media of chalk reservoirs using real reservoir material. We compare the results with outcrop samples to evaluate the effects of sulfate and rock material on wettability alteration and oil mobilization. We conduct dynamic contact angle measurements and coreflooding experiments in reservoir conditions. Our findings contradict the previous observations, as we discovered that decreasing the sulfate concentration in the displacing fluid causes a shift in the reservoir chalk's wettability to a more water-wet condition, which significantly improves oil mobilization. We also establish that outcrop chalk samples, typically used in laboratory experiments, cannot be used as reliable analogues for reservoir chalk samples with the same geological age. Finally, we use direct pore scale simulations to demonstrate the impact of observed wettability alteration on oil mobilization. Our simulation results align with our experimental findings, indicating that wettability alteration is the primary mechanism in our experiments, as fluid-fluid interactions were ignored, and flow was mainly controlled by the medium's wettability state.

Studying the effect of various surfactants on the possibility and intensity of fine migration during low-salinity water flooding in clay-rich sandstones

In the majority, sandstone reservoirs contain clay particles. When such reservoirs are exposed to low-salinity water, multi-ion exchange (MIE) and electrical double layer (EDL) expansion result in fine migration, which sweeps residual oil in the porous media while imposing damage and permeability reduction.This research investigates the effect of surfactants on the possibility and intensity of fine migration in clay-rich sandstones. First, the impact of these surfactants on the surface charge of quartz and clay particles was investigated. The results showed that both CTAB (CetylTrimethylAmmonium Bromide) and QS (Quillaja Saponin) lower the magnitude of fine particles' zeta potential from −40 mv to 2 and -18 mv, respectively, The zeta potential compensation weakens the repulsive forces. However, SDS (Sodium Dodecyl Sulfate), and TX (Triton X-100) do not change the magnitude of zeta potential. The surfactants were injected at a concentration of 10 g/L into sandpacks containing 5 wt% of kaolin. SDS and TX couldn't prevent fine migration, and sandpack permeability decreased from 65 md to about 8. CTAB completely prevented fine migration (permeability reduction from 66 to 62md). Meanwhile, QS reduced the intensity of fine migration and the permeability decreased to 30 md. Post-flushing diluted surfactant solutions showed that CTAB loses its ability to control fine migration and the magnitude of permeability drops to 8 md. However, QS still controlled the intensity of fine migration.CTAB, QS, SDS, and TX-100 adsorption on oil-aged sandstone rocks lower the contact angle from 1290 to 21.20, 69.50, 52.70, and 62.10, respectively. It should be noted that the aging time for this experiment was 14 days, which was conducted at 60 °C. contact angel studies illustrated that EDL compaction by surfactants can cause wettability alteration toward water wet conditions, through adsorption in the stern layer, which results in oil desorption. BET analysis showed that the kaolinite particles are mesoporous with weak interaction, which are covered by CTAB or QS adsorption. However, after lowering the surfactant concentration in the bulk fluid, CTAB is desorbed, resulting in the revival of pores. In contrast, desorption in QS dilution was negligible. The behavior difference is related to the adsorption mechanism. CTAB is absorbed on the particle surface based on cation exchange and QS due to hydrogen bonding. In QS, the hydrophilic part is adsorbed on the particles, and the hydrophobic part forms the external surface, which prevents water from reaching the hydrophilic part.

Molecular dynamics simulation of the diffusion crystallization mechanism of the binary alkane mixture nC5H12–nC24H50 under the water-wetting condition of a pipe wall

Wax deposition on the inner wall of oil pipes, sucker rods, oil- and gas-gathering pipelines and equipment caused by wax crystals has been a challenging problem in the petroleum industry. At present, most of the marine terrestrial transitional facies and continental shale oil and gas being explored and developed in China have high-wax-content volatile oil or condensate, and many shale oil and gas wells have been seriously blocked by wax deposition. In this work, the wax deposition behavior of the binary alkane mixture nC5H12–nC24H50 at different temperatures under the condition of water wetting of a pipe wall was studied through molecular dynamics simulation. When the temperature is 130–70 °C, the wax molecules are loosely distributed without obvious aggregation, and the pipe wall is mainly occupied by water molecules, exhibiting a water-wetting state. With the decrease in temperature, the distance between nC24H50 molecules decreases correspondingly, which enhances the interaction between wax molecules and increases the probability of mutual aggregation. When the temperature is 50 °C, a small amount of nC24H50 molecules pass through the water molecular layer and gather on the pipe wall. When the temperature is <50 °C, the binding energy between the crystal surface of the pipe wall and the molecule nC24H50 exhibits a first-order phase transition, and the molecule nC24H50 can more easily bind to the pipe wall than the molecule H2O. When the temperature is 40–20 °C, the aggregation amount of nC24H50 molecules on the pipe wall further increases, exhibiting an obvious crystallization tendency, and a small amount of nC5H12 molecules begin to aggregate with nC24H50 molecules through the water molecular layer on the pipe wall. At the same temperature, the diffusion speed of nC24H50 molecules in nC5H12 is faster than that in H2O.

Insights into the Microscopic Oil-Water Flow Characteristics and Displacement Mechanisms during Waterflooding in Sandstone Reservoir Rock Based on Micro-CT Technology: A Pore-Scale Numerical Simulation Study.

The low oil recovery rate observed in current oil fields is largely attributed to the presence of remaining oil trapped in the pores of porous media during waterflooding. To improve the recovery rate, it is imperative to gain an understanding of the oil-water flow characteristics and displacement mechanisms during waterflooding, as well as to elucidate the underlying mobilization mechanisms of residual oil at the pore scale. In this paper, we explore these issues in depth by numerically investigating the influence of factors such as water injection velocities, oil-water viscosity ratios, and wettability conditions on pore-scale oil-water flow characteristics and oil recovery rate. To this end, we employ a direct numerical simulation (DNS) method in conjunction with the volume of fluid (VOF) method to study the microscopic displacement mechanisms of waterflooding in a reconstructed two-dimensional digital rock core based on micro-CT technology. In addition, the particle tracing method is adopted to identify the flow path and dominant areas during waterflooding in order to mobilize the residual oil within the pores. The findings indicate that the oil-water flow characteristics in porous media are determined by the interplay between capillary and viscous forces. Furthermore, the oil recovery rate is 10.6% and 24.7% lower under strong water-wet and oil-wet conditions than that (32.36%) under intermediate wettability conditions, and the final oil recovery rate is higher under water-wet conditions than under oil-wet conditions. The seepage path and the dominant areas are directly linked to the capillarity formed during waterflooding. The findings of this study are significant in terms of enhancing the recovery rate of residual oil and provide a novel perspective for understanding the waterflooding process.

The Effect of Nano Heavy Metal Oxide Particles on the Wettability of Carbonate Reservoir Rock

Summary Production of oil from carbonate rocks is very challenging due to their inherent nature, such as detection, complex wettability, pore structure, and low recovery factor. Nanoparticles (NPs) are recognized as remarkable materials for a wide range of research and commercial applications due to their physical properties and characteristics. Extensive research in recent years has shown that nanoscience can provide great potential for the development of carbonate reservoirs and enhanced oil recovery (EOR). In this study, the carbonate core plug samples were prepared from an Iranian reservoir. At first, the wettability capacity of the core samples was evaluated. This process was carried out by evaluating wettability changes using the contact angle of base fluid and nanofluid. The potential of the NPs (ZnO, TiO2, and ZrO2) to change the wettability was experimentally tested in the loading NPs from 0.01 wt% to 0.5 wt% by the contact angle method. Wettability studies have shown that nanofluids can influence wettability variability from oil-wet to water-wet quality. About 0.05 wt% of NPs was found to be the optimal concentration to affect wettability change. The same behavior was observed for all nanofluids at the same NP loading; while TiO2 showed better performance with a sharp change from an oil-wet state (θ = 151.9°) to a water-wet state (θ = 111.3°), ZnO, and ZrO2 changed wettability to a moderately-wet condition (θ = 108.6° and 118.6°, respectively) at 0.05 wt% NP loading. We conclude that TiO2-based nanofluids have great potential as EOR agents, and TiO2 is very impressive in its strong water-wettability. The highest oil recovery in the optimal amount for all three nanofluids was obtained as 35.2%, 23.2%, and 25.6%, respectively, for TiO2, ZnO, and ZrO2 nanofluids. Furthermore, we considered the effect of nanofluids on the recovery performance of the brine/oil system for carbonate core samples. The results showed that nanofluids can significantly imbibe into the core sample, and as a result, the final oil recovery is significant.

Two-phase displacement dynamics in fractured porous media of varying wettability states: A micromodel experimental investigation of matrix/fracture interactions

Matrix-fracture interactions are significant in determining multiphase flow behavior in fractured porous media. We investigated the impact of these interactions on dynamic displacement events and flood-front patterns in a fractured micromodel, with two matrix regions having different permeabilities, of varying wettability states. The effects of injection rate and viscosity were studied during the injection of blank brine and polymer solutions, respectively, under oil-wet (hydrophobic) and water-wet (hydrophilic) conditions. The influence of reducing interfacial tension was examined by injecting a surfactant solution into the oil-wet micromodel. Under oil-wet conditions, brine invaded the high-permeability matrix producing a stepwise increase in water saturation during the low and intermediate rate experiments. The high rate induced fluid displacements within both matrices, but trapped more oil in the high-permeability zone due to what we labeled as the high-rate interruption effect. The stepwise invasion was also observed in the two matrices during the polymer solution injection, contrary to the smoother invasion of the surfactant solution. In the water-wet model, the high-permeability matrix exhibited final fluid saturations resembling those in the oil-wet model after brine injection. However, unlike in the oil-wet model, brine invaded the low-permeability matrix. The polymer solution suppressed trapping and improved the sweep efficiency across the two matrix regions. Our results provide new insights into the pore-scale evolution of fluid saturation during two-phase flow in fractured porous systems under varying wettability conditions.

The stabilization of oil-bound thin brine films over a fixed substrate with electrically charged surfactants subject to van der Waals and electrostatic forces

Enhanced oil recovery through low salinity water flooding has been attributed to increased rock-to-water wettability due to the stabilization of a thin brine film between the rock and the oil phase resulting from the expansion of the electric double layer. However, the underlying physicochemical mechanisms are not well understood and an electrohydrodynamic approach to the thin film dynamics helps to better understand its evolution to equilibrium states. Lubrication theory is applied to a thin brine film bounded by a viscous phase with diffusing charged surfactants at the oil–brine interface under van der Waals and electrostatic interactions. Linear analysis and numerical solutions of the nonlinear governing equations are carried out and linear stability diagrams indicate that disturbances evolve in oscillatory or non-oscillatory modes. In addition to the expansion of the electric double layer, other physicochemical mechanisms affect the stabilization of the brine film. Among them are the (secondary) ionic hydration within the brine, surface charge concentrations, diffusion of surface-active species, as well as Marangoni, tangential and normal stresses. In the nonlinear regime, the van der Waals attraction leads to rupture in regions where the film is narrower since primary hydration is not considered. The oil–brine interface may be negatively or positively charged and different mechanisms can change the wettability of rock formations. Including hydration forces led to nonlinear metastable states, in addition to linearly stable states. The findings help design ’smart waters’ based on modifying the properties of surfaces and adjacent fluids of thin liquid films in order to drive positively or negatively charged rock formations into more water-wet states.

Impact of wettability on storage and recovery of hydrogen gas in the lesueur sandstone formation (Southwest hub project, Western Australia)

Geological storage has been proposed as a new technology to temporarily store significant amounts of hydrogen (H2) gas in depleted gas reservoirs, underground salt caverns, or saline aquifers. Often, such subsurface reservoirs naturally contain trace amounts of organic acids, and these compounds can considerably alter the wettability of reservoir rocks, causing them to become less water-wet. We carried out Molecular Dynamics (MD) simulations of contact angles in a quartz-brine-H2 system to evaluate wettability in realistic subsurface situations. MD simulations suggest that Humic acid makes quartz more hydrophobic, which can affect the overall behaviour of the storage reservoir. For the first time, this effect was experimentally investigated for a natural sandstone reservoir from the South West Hub Project, i.e., the Lesueur Sandstone (LS) formation. Multi-stage core flooding experiments were conducted on the same LS plug to investigate the impact of wettability alteration on initial and residual hydrogen saturation/trapping at depth. First, consecutive brine-H2 drainage-imbibition cycles were carried out on the natural sample; the result indicated that the rock-brine-H2 system was essentially water-wet. Then, the sample was aged in Humic acid with a molarity of 10−2 M for 42 days at 5 °C and 0.1 MPa. The wettability of the storage system shifted toward a less water-wet state, i.e., more hydrophobic. As a result of Humic acid ageing, the initial hydrogen saturation reduced from 29% to 15%, and the residual hydrogen trapping reduced from 23% to 11%. This is attributed to a change induced in the capillary force (i.e., snap-off) controlled by wettability and pore size. In addition, the wettability change induced by Humic acid increased the hydrogen recovery rate from 20.7% to 26.7%.