Oil-wet Conditions Research Articles

Low-salinity water flooding by a novel hybrid of nano γ-Al2O3/SiO2 modified with a green surfactant for enhanced oil recovery

This paper introduces a hybrid enhanced oil recovery (HEOR) method that combines a low-salinity water flooding (LSWF) and nanoparticles (NPs) stabilized with a green surfactant. We experimentally investigated the use of combinations of silica (SiO2) and gamma alumina (γ-Al2O3) nanohybrids stabilized with Gum Arabic (GA) at different water salinities. Nanofluids (NFs) were prepared by dispersing γ-Al2O3 and SiO2 NPs (0.1 wt%) in deionized water (DW), synthetic seawater (SSW), 2, 5, and 10 times diluted samples of synthetic seawater (in short 2-DSSW, 5-DSSW and 10-DSSW, respectively). The challenge is that NPs become unstable in the presence of cations in saline water. Moreover, an attempt was made to introduce NFs with high stability for a long period of time as the optimal NFs. The effects of temperature on the behaviour of optimal NFs in the presence of different base fluids, distinct mass ratios of γ-Al2O3/SiO2 and various concentrations of surfactant were analysed via interfacial tension (IFT) and viscosity measurements. The results of the viscosity measurement showed that with increasing temperature, the NPs dispersed in DW had lower viscosity than NPs dispersed in various salinities. However, the IFT measurement for NPs dispersed in different base-fluids revealed that with increasing temperature and presence of cations in saline water, IFT values decreases. Although, the minimum IFT for hybrid nanofluid (HNF) γ-Al2O3/SiO2 modified with GA and dispersed in 10-DSSW was reported 0.99 mN/m. Finally, according to the micromodel flooding results, in oil-wet conditions, the highest oil recovery for combination γ-Al2O3/SiO2 modified with GA and dispersed in 2-DSSW was reported 60.34%. It was concluded that NFs modified with GA could enhanced applicability of LSWF via delay in breakthrough time and improving sweep efficiency.

Different effects of resins and asphaltenes concentration of crude oil on sandstone wettability

The influence of asphaltenes in crude oil on sandstone wettability is widely acknowledged. Although asphaltenes are recognized for their stronger polarity compared to resins, resins also contain the similar acidic and nitrogen-containing compounds to those found in asphaltenes. Nevertheless, the impact of resin adsorption on altering sandstone wettability, the different effects of vary concentrations of resins and asphaltenes, and their microscopic mechanisms influencing sandstone surfaces remain ambiguous. Thus, in this study, resins and asphaltenes were isolated from crude oil individually to investigate the different effects of their concentrations on sandstone wettability and the specific reasons. The contact angle measurements, atomic force microscopy (AFM), energy dispersive spectroscopy (EDS), and Cryo-environmental scanning electron microscopy (ESEM) were used to examine and explain the wettability changes of Berea sandstone slices before and after exposure to varying concentrations kerosene solutions of resins and asphaltenes. The results reveal that sandstone wettability could not be changed from strongly water-wet to oil-wet, even at resin concentrations as high as 50.0 mg/mL kerosene. In contrast, lower concentrations of asphaltenes, equivalent to a 5.0 mg/mL kerosene threshold, can facilitate the wettability transition process. After the adsorption of resins and asphaltenes, the roughness of the clay surface changes much more significantly than that of the quartz surface. Combined with the observation of ESEM and the results of EDS, it is believed that the resins and asphaltenes preferentially adsorb to clay surfaces, especially chlorite, rather than quartz surfaces. Clay could provide favorable sites for the accumulation of oxygen-containing compounds, leading to enduring clay-organic complexes that serve as anchor molecules for the adsorption of other compounds, ultimately causing the sandstone surface to an oil-wet state. These results may provide theoretical support for better core aging process in the laboratory, surfactant development and enhanced oil recovery procedure optimization in the oilfield.

Work Flow Screens Surfactants for EOR Through Wettability Alteration

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3866246, “A Systematic Laboratory and Model-Based Surfactant Screening Work Flow for Enhanced Recovery Through Wettability Alteration in the Eagle Ford,” by Jason Jweda, SPE, Russ Bone, SPE, and Hesham El-Sobky, ConocoPhillips, et al. The paper has not been peer reviewed. _ Previous experimental studies and published field trials have shown that injected surfactants can be an effective means of improving recovery. Most experiments, however, have been conducted at ambient rather than reservoir conditions. The complete paper presents a novel approach to screen thermally stable surfactants at high pressures and high temperatures for the explicit purpose of wettability alteration in the operator’s Eagle Ford acreage. Early Internal Efforts Surfactant usage was initiated at the inception of the play. The use of these surfactants was discontinued after approximately 5 years of field development. Fieldwide performance analysis confirmed that off-the-shelf surfactants, on average, did not improve long-term performance statistically. Initial laboratory screening of bespoke surfactant chemistries commenced a few years later. To test surfactant properties near Eagle Ford reservoir conditions, a novel microfluidics experiment was conducted using synthetic microchips designed with reservoir specifications. Twenty-six flowback tests with Eagle Ford crude oil were conducted at 300°F and up to 3,800 psi with six different commercial surfactant chemistries. Imbibition results with the six commercial surfactants were compared with a control case with make-up brine water. Testing performed at 2 gal/thousand increased overall performance for the oil-wet conditions but decreased performance for mixed-wet conditions when compared with 1 gal/thousand. The surfactants tested in this series were temperature-dependent and had clogging tendencies of varying degrees within the microfluidics chips. Methods and Work Flow Promising results from the Amott cell imbibition and other experiments encouraged the authors to evaluate surfactants more holistically, with an emphasis on testing at Eagle Ford reservoir conditions. The first set of experiments involved fluid-stability tests, contact-angle measurements, interfacial-tension (IFT) measurements, static spontaneous-imbibition experiments, and completion-fluid-compatibility tests. An extensive set of commercially available surfactants was screened. The highest potential cationic and nonionic cosurfactant blends that passed through fluid stability, contact-angle, and static spontaneous-imbibition experiments were selected for hydraulic stimulation-fluid compatibility tests. After the compatibility tests, the two best-graded cationic and nonionic cosurfactant blends were used in a novel flowback experiment coupled with multistage nuclear magnetic resonance (NMR) measurements. Mechanistic reservoir simulation models were used to evaluate the production effect of wettability change caused by surfactant injection. The combination of laboratory-based experimentation and reservoir simulations provided strong confidence in holistically evaluating the potential of cosurfactant blends in the Eagle Ford.

Effect of the capillarity and viscosity on the change of flow paths during two-phase displacement in porous media

Pore-scale direct numerical simulations were conducted to explore the changes of flow paths and dynamic distribution of water-oil phases during two-phase displacement in porous media. Three contact angles, i.e., 45°, 90°, and 135°, correspond to water-wet, intermediate-wet, and oil-wet rock surfaces, respectively. The medial axis within complex pore channels is obtained using a grid-based method. Subsequently, a novel particle tracking-based approach is proposed to extract the flow paths during two-phase displacement. The results show that when water enters a porous medium filled with oil, the distribution of oil phase flow paths is uniform, indicating that all oil phases are movable. As water continues to be injected, some water-oil interfaces stop at pores or throats due to capillary force, causing the flow paths through these locations to disappear. In oil-wet and intermediate porous media, capillary forces always act as resistance; therefore, the water-oil interfaces stop at the throat channels. Interestingly, under water-wet conditions, the water-oil interface can reverse, and the capillary force presents resistance, resulting in the interfaces being blocked at enlarging areas, usually from throats to pores. Once breakthrough occurs, preferential flow paths for pure water are established, resulting in a rapid decrease of flow paths with moving water-oil interfaces under oil-wet and intermediate-wet conditions, while movement continues in a water-wet medium. Due to the typically lower viscosity of water than oil, the viscous force decreases as water saturation increases. As water injection continues, the water in some channels gradually displaces oil, resulting in differences in flow rates between oil-filled and water-filled channels. This study provides a method for identifying the changes in flow paths during two-phase displacement in porous media and gives potential benefits for designing strategies to improve oil recovery.

Pore-scale study of the effects of DTPA chelating agent flooding on oil recovery utilizing a clay-coated micromodel

The use of diethylenetriaminepentaacetic acid (DTPA) chelating agent has shown promising results for enhanced oil recovery (EOR) in prior research. Several mechanisms, mainly resulting from rock-fluid interaction, have been proposed for chelating agent flooding; however, little attention has been paid to fluid-fluid interaction thus far. The assessment of these mechanisms has primarily relied on macroscopic techniques such as core flooding. This paper aims to investigate the injection of DTPA brine and its dominant mechanisms at the pore scale using a clay-coated micromodel. The micromodel tests were performed under oil-wet and water-wet states. For a more precise examination of fluid/fluid interactions, the dynamic interfacial tension (IFT) and Zeta potential were measured. It was observed that the injection of DTPA brine in water-wet state changed the saturation distribution and increased oil recovery. Based on visual inspections, this change in saturation distribution could potentially be linked to the formation of micro-dispersions and viscoelastic interfacial phenomena. Micro-dispersions facilitate flow to unswept areas, and viscoelastic interface formation reshapes the interface between oil and brine, causing disconnected oil droplets to coalesce and thus increase recovery. Under the oil-wet state, the micro-dispersion formation and wettability alteration can be the dominant mechanisms, and the amount of recovered oil was higher than that observed in the water-wet state. Furthermore, Zeta potential measurements at the interface between brine and oil showed a more negative value for DTPA brine, which is effective in wettability alteration and micro-dispersions stability. The results indicate that IFT reduction was not significant enough to be considered the dominant mechanism, although it assists in DTPA brine penetration into the crude oil and subsequent micro-dispersion formation.

The Micro-Flow Mechanism of Polymer Flooding in Dual Heterogeneous Reservoirs Considering the Wettability.

There have been some studies conducted about the single factor viscoelasticity of polymer solution or wettability effect on the micro-flow mechanism of polymer flooding. In this paper, the flow mechanism of polymer solution in dual heterogeneous reservoir considering the wettability and gravity was studied. The influences of wettability and rock particle shape on flow characteristics were studied based on the characteristics of saturation and pressure distribution. Compared with the simulation results of polymer flooding in three different rock particle shapes porous media, the oil displacement efficiency of the circular particle model is the highest at 91.57%, which is 3.34% and 11.48% higher than that in the hexagonal and diamond models, respectively. The influence of wettability was studied by the circular particle model. The oil displacement efficiency under water-wet conditions was higher than that under oil-wet conditions. The displacement process considering gravity was affected by the crossflow caused by gravity and viscous force, and the micro-oil displacement efficiency was 9.87% lower than that of non-gravity. Considering the wettability, vertical crossflow will be formed. The oil displacement efficiency under water-wet conditions was 3.9% higher than in oil-wet conditions. The research results can not only expand and enrich the micro-flow mechanism of viscoelastic polymer solution, but also provide reference and guidance for polymer flooding scheme design.

Mechanistic fouling study of Hybrid imidazolium-based ionic liquid membrane during emulsified oil removal from oily wastewater; oil type effect

To overcome the strict discharge effluent regulations of oily wastewater, the treatment with membranes has a good perspective. In this work, [C12mim][Cl] ionic liquid was induced into the polyether sulfone membrane to improve membrane hydrophilicity and anti-fouling resistance. To reveal the membrane fouling type, the permeate flux of the membrane was modeled according to Hermia's equations and combined equations driven from four main fouling mechanisms equation. In addition, to develop a proper interpretation and fully new insights mechanisms, the elemental and topographical analyses, and chemical surface characterizations using FESEM, EDS MAPPING, AFM, FESEM, Zeta analyses, and contact angle and interfacial tension measurements were performed on the four different oily wastewaters and the membrane. So, the impact of interfacial tension, wettability, mean particle size, particle size distribution (polydispersity index), zeta potential, acidic and basic nature of oil, and the properties of polar fractions of oil including the asphaltene and resin concentrations and their weight percent of polar heteroatoms were thoroughly examined. The results revealed a reduction in permeate flux as the API gravity was reduced due to the particle size of the oily wastewater emulsion increased. Consequently, the wettability of the membrane altered towards a more oil-wet state leading to a reduction in the roughness of the membrane surface. The attachment and cover of the surface mainly by the acidic component of the oil with a higher affinity to attach the oxygen element of the membrane were proposed as the dominant mechanism of cake layer fouling.

Investigation on the synergistic effect of pH and pyridinium-based ionic liquid on the wettability alteration of dolomite rock and IFT of formation brine/alkaline crude oil at the presence and absence of SiO2 nanoparticles

Investigation on the hybrid enhanced oil recovery solutions and methods is gaining attention during the last decade since they can activate multiple mechanisms such as viscosity reduction, interfacial tension (IFT) reduction, and wettability alteration. So, the current work is concentrated on the application of 1-octyl-3-methyl pyridinium chloride ([C8py][Cl]) and 1-dodecyl-3-methyl pyridinium chloride ([C12py][Cl]) as novel surfactants in the absence and presence of SiO2 nanoparticles (SiO2-NPs) for the first time for possible IFT reduction and rock wettability change (contact angle (CA) measurement). In this way, the concentration of ionic liquids (ILs) and SiO2-NPs ranged between 0–2000 ppm and 0–1000 ppm, respectively, to see the influence of these chemicals on the wettability change and IFT reduction. The point is that the higher concentrations of these chemicals were not examined since using higher concentrations makes it expensive and uneconomic for field-scale applications. The obtained results revealed that as the pH increases from 3 to 11 in the absence of different chemicals (formation brine/basic crude oil), the IFT experiences an increase from 20.3 to 31.2 mN/m, while the situation for CA is more complicated. In detail, the results revealed that increasing the pH in the range of 3–11 leads to an increase in the CA from 103.2° to 121.3° (increasing pH from 3 to 7) while a further increase in the pH leads to a reduction in CA value from 121.3° to 118.3°. Moreover, the results revealed that increasing the concentration of [C8py][Cl] from 0 to 2000 ppm led to a reduction in IFT value from 20.3 to 0.95 mN/m for pH of 3, from 27.3 to 2.2 mN/m for pH of 7 and from 31.2 to 5.4 mN/m for pH of 11. Besides, the measurements for [C12py][Cl] revealed that increasing the concentration from 0 to 2000 ppm leads to IFT reduction from 20.3 to 0.74 mN/m for pH of 3, from 27.3 to 0.9 for pH of 7, and from 31.2 to 1.4 mN/m for pH of 11. The results demonstrated a higher influence of [C12py][Cl] on the IFT reduction compared with the [C8py][Cl] due to the longer alkyl chain length of [C12py][Cl] which means more detergency power. Furthermore, the effects of these two ILs are examined on the wettability change which showed that both of the examined ILs are capable to manipulate the wettability of the rock surface toward water-wet conditions (53.3°) from oil-wet conditions (121.3°). Also, the influence of SiO2-NPs in the range of 0–1000 ppm is investigated on the IFT reduction and wettability change while the concentration of ILs is held constant at 2000 ppm since the concentration of 2000 ppm leading to the lowest CA and IFT values for both examined ILs. The obtained results reveal that not only the presence of SiO2-NPs with a maximum concentration of 1000 ppm leads to a reducing trend on the IFT in particular for the pH of 11 regardless of the used IL but also it changes the surface wettability to strongly water-wet condition with minimum CA value of 28.5°. In the last stage, the efficiency of the optimum chemical formulations was examined through core flooding experiments using conventional core flooding procedure and the core flooding experiments concomitant with the soaking time (30 days). The experiments revealed that the chemical formulation under a pH of 3 leads to the highest oil recovery factors while the lowest oil recovery factors are obtained under a pH of 11. Besides, the core flooding experiments followed by soaking reveal the ultimate oil recovery of 10.1 and 13.3% based on the original oil in place (OOIP) due to better activation of the wettability change mechanism which was 46% higher than the situation no soaking was performed. The findings of this study can help for a better understanding of the feasibility and applicability of using new hybrid surfactant-NPs-based EOR methods to activate wettability alteration and IFT reduction, especially with a main focus on one specific fraction of crude oil (resin fraction) instead of crude oil.

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.

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.

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%.

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.

Pore-scale modeling of two-phase flow: A comparison of the generalized network model to direct numerical simulation.

Despite recent advances in pore-scale modeling of two-phase flow through porous media, the relative strengths and limitations of various modeling approaches have been largely unexplored. In this work, two-phase flow simulations from the generalized network model (GNM) [Phys. Rev. E 96, 013312 (2017)2470-004510.1103/PhysRevE.96.013312; Phys. Rev. E 97, 023308 (2018)2470-004510.1103/PhysRevE.97.023308] are compared with a recently developed lattice-Boltzmann model (LBM) [Adv. Water Resour. 116, 56 (2018)0309-170810.1016/j.advwatres.2018.03.014; J. Colloid Interface Sci. 576, 486 (2020)0021-979710.1016/j.jcis.2020.03.074] for drainage and waterflooding in two samples-a synthetic beadpack and a micro-CT imaged Bentheimer sandstone-under water-wet, mixed-wet, and oil-wet conditions. Macroscopic capillary pressure analysis reveals good agreement between the two models, and with experiments, at intermediate saturations but shows large discrepancy at the end-points. At a resolution of 10 grid blocks per average throat, the LBM is unable to capture the effect of layer flow which manifests as abnormally large initial water and residual oil saturations. Critically, pore-by-pore analysis shows that the absence of layer flow limits displacement to invasion-percolation in mixed-wet systems. The GNM is able to capture the effect of layers, and exhibits predictions closer to experimental observations in water and mixed-wet Bentheimer sandstones. Overall, a workflow for the comparison of pore-network models with direct numerical simulation of multiphase flow is presented. The GNM is shown to be an attractive option for cost and time-effective predictions of two-phase flow, and the importance of small-scale flow features in the accurate representation of pore-scale physics is highlighted.

Effect of oil carboxylate hydrophobicity on calcite wettability and its reversal by cationic surfactants: An experimental and molecular dynamics simulation investigation

The oil-wet state of carbonate reservoirs presents a serious challenge for oil recovery. While cationic surfactants are able to reverse the wettability, their efficiency depends on the oil composition, particularly on the carboxylates as the main surface-active compounds. In this study, calcite surface was aged by two distinct carboxylates: a shorter, less hydrophobic octanoate and a more hydrophobic stearate. The surface wettability and its reversal by a quaternary ammonium cationic surfactant were studied both experimentally by contact angle measurements and Scanning Electron Microscopy (SEM) imaging, and by molecular dynamics (MD) simulations. Both simulations and experiments show that aging with the more hydrophobic stearates yields more strongly oil-wet surfaces, whose wettability is more difficult to reverse by the cationic surfactant, than aging with octanoates. While the surfactant ultimately reverses the wettability in both cases, significantly higher surfactant concentration is required for the stearate-aged calcite. The difference in the wettability can be rationalized by the greater hydrophobicity of the stearate, which strengthens both the surface adsorption and attraction of the non-polar oil phase.

Three-Phase Fluid Flow Interaction at Pore Scale during Water- and Surfactant-Alternating Gas (WAG/SAG) Injection Using Carbon Dioxide for Geo-Sequestration and Enhanced Oil Recovery

Sequestration of CO2 in geologic formations such as depleted oil reservoirs has emerged as one of the lead solutions to tackle greenhouse gas emissions to reduce pollution and global warming. Supercritical CO2 (sc-CO2) injection in oil reservoirs has proven to be useful as an enhanced oil recovery (EOR) technique along with the benefits of CO2 sequestration. In this study, a tortuous microscopic pore scale model was used to study and investigate the phenomena of water-alternating gas (WAG) and surfactant-alternating gas (SAG) with sc-CO2. The study scrutinizes the dynamics of the pore-level phenomenon in the multiphase WAG and SAG flows at the pore level in detail. Transient computational fluid dynamics (CFD) analysis was used to study the fluid flow characteristics of oil, water, and sc-CO2 at different reservoir pressure and temperature conditions in oil-wet conditions. Governing equations were coupled with EOS (Helmholtz free energy equation) to capture the viscous and intrinsic properties of sc-CO2 due to variations in pressure and temperature conditions. It was found that higher oil recovery does not necessarily indicate higher sc-CO2 sequestration and that temperature harms the displacement mechanism due to unfavorable mobility ratios. Comparing WAG and SAG for the first injection cycle, SAG showed a more diffused interface between displaced and displacing fluid. The additional oil recovery produced in patches was a result of pressure oscillations near the blind pores. Moreover, high vorticity promotes greater intermixing between the displacing and displaced fluid by increasing the rate of interface length. In SAG cases, faster sc-CO2 breakthroughs were observed due to reduced shear stress along the fluid interfaces, which resulted in higher sequestration values in a given time frame. The CO2 sequestration volume in SAG cases was found to be approximately 40% more than in WAG experiments. The study confirms that lower values of oil–water interfacial tension aids in faster and more efficient sequestration of sc-CO2 along with additional oil gain from a given reservoir.

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

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

Experimental investigation of the water bypass phenomenon in light oil reservoirs using a glass micromodel and sand cores with a hydrophobic material

A large volume of water is bypassing oil and comes up without being able to push it out from the reservoir after organic material adsorption. This work investigates hydrophobicity effect on rock wettability, oil recovery, and relative permeability. The μXRF was used to characterize sand cores, and a contact angle goniometer to determine fluids contact angle. Oil recovery was evaluated by measuring the incremental oil volume recovered in a glass and PVC capillary designed micromodel. Relative permeability was studied using the steady state method, and the wettability was determined by the Amott method. The results show that cores are mainly composed of quartz 86.04%. Oil recovery was 30.50% for oil-wet state; where the wettability index was −0.283. Thereafter, it has been demonstrated that the surfactant solution increases the oil recovery with 23.54 ℅. Adsorption of surfactants on functional groups of PVC change the contact angle between water and PVC’s surface from 112° to 39°, decrease the IFT and restore the water-wet state. PVC debris presents efficient new method to determine the water by pass effect on oil recovery. The findings of this study help for better understanding the surfactant-oil displacements during water flooding in light oil reservoirs with impaired wettability.

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.