Imbibing Fluid Research Articles

Spontaneous imbibition in thin anisotropic fibrous media: Experiments and numerical modeling

In this study, we investigate the temporal and spatial evolution of wetting saturation during spontaneous imbibition in anisotropic fibrous porous media using both experimental and numerical methods. We present a novel experimental approach to systematically study spontaneous imbibition in these media, allowing for a comprehensive assessment of how microstructure influences wicking performance. The experimental method, which exhibits high reproducibility, was used to validate the numerical model. The numerical model was parameterized using only the porosity and filament diameter of the porous media in conjunction with the material properties of the imbibing fluid. The essential capillary saturation curve for the numerical model was derived using the pore morphology method. The numerical results effectively replicated the experimental results. Our experimental and numerical observations revealed a diffusive wetting front within the porous media, which progressively expanded and decelerated during the imbibition process. The results highlight the significant influence of filament size on the wetting saturation dynamics and the height of the wetting front during spontaneous imbibition.

Anisotropy and Fiber Orientation: A Key Player in the Lateral Imbibition of Cellulose Paper

In this article, we delve into the influence of fiber orientation (structural anisotropy) on paper imbibition, with a particular focus on in-plane imbibition. Utilizing the XLPA experimental method, we analyze several papers with different anisotropies, employing a constant volume of ethanol as the imbibing fluid. Our findings contribute novel insights into the anisotropic behavior of imbibition, a topic not extensively covered in the literature. We analyze how the orientation of fibers significantly influences lateral imbibition, providing a deeper understanding of the microfluidic properties of paper. The anisotropies found for imbibition fit perfectly with the existing data found in the literature, indicating the influence of fiber orientation. Furthermore, the kinetics are shown to be linked directly with the porosity.

Using magnesium oxide nanoparticles in a magnetic field to enhance oil production from oil-wet carbonate reservoirs

Enhanced oil production can maximise yield from depleted reservoirs, and in the face of dwindling global oil reserves can reduce the need for exploratory drilling during the transition away from fossil fuels. A hybrid technique, merging a magnetic field (MF) and magnesium oxide (MgO) nanoparticles (NPs), was investigated as a potential method of enhancing oil production from oil-wet carbonate reservoirs. The impact of this hybrid technique on rock wettability, zeta potential, and interfacial tension was also investigated. Displacement experiments were carried out on oil-wet Austin chalk – a laboratory carbonate rock analogue – using MgO NPs in deionized water (DW) and salt water (SW), in the presence of an MF up to 6000 G in strength. It was found that the addition of MgO NPs to DW before the spontaneous imbibition of the solution into initially oil-wet rock samples increased the recovery factor (RF, defined as the volume of oil recovered divided by the initial oil in place). For 0.005 wt% and 0.0025 wt% MgO NPs mixed in DW, the RF was 12.5% and 15.9% respectively. When DW was replaced with SW as the imbibing fluid, the RF increased by a further 0.7% of initial oil in place for the 0.0025 wt% MgO NPs. This additional increase in oil recovery was attributed to the presence of potential determining ions, which made the rock more water-wet. To avoid pore-clogging and thus the limited ingress of the solution into the rock, the NPs’ concentration was kept low. This hybrid technique is a cleaner alternative to conventional enhanced oil recovery techniques and will enable oil industries to produce oil more efficiently from existing reservoirs: when used in conjunction with Carbon Capture and Storage (CCS), this provides a useful short to medium-term option to support energy production during the transition to net zero.

Investigating the potential of microbial enhanced oil recovery in carbonate reservoirs using Bacillus persicus

In this study, several laboratory experiments were conducted to evaluate the performance of Bacillus persicus as a microbial enhanced oil recovery (MEOR) agent in conventional and fractured carbonate reservoirs. In these experiments, it was observed that using the microbial solution as an imbibing fluid can produce 12.5% of the original oil in place. Complementary imbibition experiments demonstrated that lower recoveries are achievable using Sodium Dodecyl Sulfate (SDS) surfactant and supernatant solutions. In order to investigate effective mechanisms, various experiments, including wettability alteration measurements, biosurfactant production tests, viscosity, and pH measurements, were performed. The contact angle tests exhibited that the selected microorganism can alter the wettability of carbonate surfaces by reducing the water/oil contact angle from 132° to 54°, representing a change from an oil-wet to water-wet state. Bacillus persicus also showed favorable results in biosurfactant production tests, including interfacial tension, emulsion index E24%, and oil displacement experiments. The viscosity measurements showed that the bacterial solution could decrease oil viscosity by about 27%. Moreover, no significant changes were found in the pH of the microbial solution during incubation and after treatment. Finally, core flooding experiments exhibited that microbial solution injection as a tertiary oil recovery method could recover 37.52% of the original oil in place. The results obtained in this study demonstrated the potential of MEOR plans targeting oil-wet/mixed-wet fractured and non-fractured carbonate reservoirs.

Modeling of early- and late-time countercurrent spontaneous imbibition in porous media: A semi-analytical approach

Countercurrent spontaneous imbibition (SI) is an important flow mechanism to recover oil in water-wet porous media through capillarity. Experimental imbibition tests conducted in core samples show that oil recovery as a function of time occurs in a characteristic S-shaped curve, which describes the infinite-acting and the boundary-dominated regime. Although several dimensionless time groups have been proposed to model countercurrent SI in porous media, they fail to properly scale the results, causing inaccurate estimates of oil recovery. In this work, we present a new approach, using a hybrid solution, to model countercurrent SI for oil-water systems dominated by capillary forces. The infinite-acting regime is modeled by an early-time solution using a new dimensionless time group, which enables the correct scaling of imbibition results onto a universal single curve. To model the boundary-dominated regime, we introduce a late-time solution derived as a function of a characteristic distribution of saturation to estimate the flow behavior after the imbibing fluid reaches the no-flow boundary. The novelty of the model is that it enables the accurate estimation of fluid imbibition under the boundary-dominated regime, a flow condition critical to evaluate the true potential of countercurrent SI driven by capillarity for oil recovery in porous media. We verified the model against numerical simulations under a wide range of flow conditions relevant in water-oil systems, and used experimental data reported in the literature to validate our model. The solution presented provides an accurate approach to model countercurrent SI, which could be extended for dynamic conditions and the modeling of the flow of fluids in fractured media.

A theoretical study on the capillary rise of non-Newtonian power-law fluids

The phenomena of capillary rise with the effect of displaced fluids are ubiquitous in both science and engineering, and the mathematical models and their analytical solutions of this problem have also received increasing attention. In this paper, a theoretical study on the rising dynamics of non-Newtonian power-law fluids in a capillary is performed, and the classical Lucas–Washburn equation is generalized to a nonlinear second-order differential equation in which the effects of the power-law index and displaced fluids are included. We analyze the imbibition behaviors of power-law fluids under the influence of displaced fluids in details, and also present some analytical solutions of different special cases and different time stages. The results show that for different special cases, it takes shorter time for shear thickening fluid to reach the equilibrium height. For different time stages, however, the rising phenomena of power-law fluids are more complex, and the average time for the shear-thinning fluid to reach the equilibrium height is longer compared to shear-thickening fluid, but an opposite phenomenon is observed for the case of μ1,0/μ2,0=100 (here μ1,0/μ2,0 is the viscosity ratio of two power-law fluids) in viscous time stage. In inertial time stages, the density ratio of the absorbed fluid to the displaced fluid also has a significant effect on the rising dynamics of imbibing fluid. Furthermore, the effect of dynamic contact angle is also included in the governing equation and analytical solutions. Through a comparison between the theoretical results and experimental data, a good agreement is observed. These results can be used as a priori for liquid absorption in industrial applications, including oil recovery, fuel cells and water collection of artificial silk.

Wettability alteration and oil recovery by spontaneous imbibition of smart water and surfactants into carbonates

Naturally fractured carbonate reservoirs have very low oil recovery efficiency owing to their wettability and tightness of matrix. However, smart water can enhance oil recovery by changing the wettability of the carbonate rock surface from oil-wet to water-wet, and the addition of surfactants can also change surface wettability. In the present study, the effects of a solution of modified seawater with some surfactants, namely C12TAB, SDS, and TritonX-100 (TX-100), on the wettability of carbonate rock were investigated through contact angle measurements. Oil recovery was studied using spontaneous imbibition tests at 25, 70, and 90 °C, followed by thermal gravity analysis to measure the amount of adsorbed material on the carbonate surface. The results indicated that Ca2+, Mg2+, and SO42− ions may alter the carbonate rock wettability from oil-wet to water-wet, with further water wettability obtained at higher concentrations of the ions in modified seawater. Removal of NaCl from the imbibing fluid resulted in a reduced contact angle and significantly enhanced oil recovery. Low oil recoveries were obtained with modified seawater at 25 and 70 °C, but once the temperature was increased to 90 °C, the oil recovery in the spontaneous imbibition experiment increased dramatically. Application of smart water with C12TAB surfactant at 0.1 wt% changed the contact angle from 161° to 52° and enhanced oil recovery to 72%, while the presence of the anionic surfactant SDS at 0.1 wt% in the smart water increased oil recovery to 64.5%. The TGA analysis results indicated that the adsorbed materials on the carbonate surface were minimal for the solution containing seawater with C12TAB at 0.1 wt% (SW + CTAB (0.1 wt%)). Based on the experimental results, a mechanism was proposed for wettability alteration of carbonate rocks using smart water with SDS and C12TAB surfactants.

Analytical solution to spontaneous imbibition under vertical temperature gradient based on the theory of spontaneous imbibition dynamics

In this work, we have theoretically studied the imbibition process related to a block in a fractured carbonate reservoir under an assumed constant, vertical temperature gradient, GT. An analytical solution to an ordinary differential equation we developed has been obtained using a computer program, and the original Washburn law normally valid for isothermal conditions of spontaneous imbibition has been found to hold true for GT equal to zero. The theoretical results of our study show that the space and time evolution of the imbibition front is strongly dependent on surface tension and dynamic viscosity of the imbibing fluid under a given temperature gradient. We have also validated our model against experimental data from a literature source based on spontaneous imbibition into a Hele Shaw Cell under longitudinal temperature gradient. The general conclusion of our study is that spontaneous imbibition in fractured carbonate reservoirs will be accelerated the higher the temperature of the injected water. This corresponds to a negative temperature gradient where the temperature of the injected water exceeds the ambient temperature of the reservoir.

Impact of water saturation and cation concentrations on wettability alteration and oil recovery of carbonate rocks using low-salinity water

In this study, the effect of initial water saturation on the oil recovery for carbonate rocks is investigated using spontaneous imbibition experiments. The experiments are performed using 20 times diluted sea water as imbibing fluid and the sea water as initial water. In addition, the impact of pH and Ca2+, Mg2+, Na+, and K+ cations concentration change of imbibing fluid are investigated during tests. These results help to identify the active cations in the wettability alteration process of carbonate rocks during the low-salinity water injection. A mechanism is proposed to describe the effect of initial water saturation on the oil recovery by low-salinity water injection. The impact of initial water saturation on the wettability alteration might be positive or negative depending on its value and the rock permeability. The comparison of divalent cations concentrations shows that the minimum adsorption of Ca2+ and maximum desorption of Mg2+ lead to maximum oil recovery of spontaneous imbibition. The results confirm that three cations of Ca2+, Mg2+, and Na+ are active for wettability alteration of carbonate rocks in the presence of sea water as initial water and diluted sea as imbibing fluid, whilst the amounts of potassium remain constant.

Expansion and shrinkage of sandstones during spontaneous imbibition of fluids

The expansion of pure quartz sandstones is investigated during spontaneous imbibition of fluids. The selected Fontainebleau sandstone samples cover a wide variation in their petrophysical properties (e.g., porosity, permeability, P-wave velocity, and effective pore size), and demonstrate expansion and shrinkage during spontaneous imbibition of fluids with different surface tension. The capillary forces cause a spontaneous imbibition of the fluid into the pore space. The wetting of the mineral grains causes a volume strain to the matrix that can be recorded as an expansion. If the rigidity of the matrix is weak, a shrinkage of the sample is observed instead of expansion. The experiments have shown that the relative expansion depends on the surface tension of the imbibing fluid, the degree of saturation, the rigidity, and the effective pore radius of the sandstone sample.

Initial water saturation and imbibition fluid affect spontaneous imbibition into Barnett shale samples

Spontaneous imbibition has been widely investigated due to its significant impact on gas/oil recovery from conventional sandstone and carbonate reservoirs. Unlike conventional reservoir rocks with relative high porosity and permeability, shale is characterized by its low porosity (<10%), ultra-low permeability (∼10−18–10−23 m2), complex wettability, and strong heterogeneity at multiple scales. This study is to understand the effects of initial water saturation and imbibing fluid on spontaneous imbibition of Barnett shale core samples taken from three different depths of Blakely #1 well in Wise County of Texas. Two partial, and yet uniform, water saturations of shale samples were achieved by equilibrating the samples inside closed containers at specific relative humidity controlled with over-saturated salts. The effect of imbibing fluids (water or oil-phase n-decane) on spontaneous imbibition behavior is evaluated by conducting replicate experiments. Our results show that the spontaneous imbibition behavior of shale samples could be affected by the initial water saturation conditions, and the effects are different for shale samples with different mineral compositions. The imbibition curves of shale samples with a high clay content show a poor reproducibility during water imbibition experiments due to the water sensitivity of clay minerals. In addition, n-decane could not be completely removed after its imbibition experiment. The interaction between remnant n-decane and shale matrix may change the sample wettability towards more oil-wet, which is indicated by a higher imbibition slope of second n-decane imbibition experiment on the same sample. Overall, this work helps understand the mechanism controlling fluid loss and ultimate gas/oil recovery in unconventional hydrocarbon exploration, which is significant for optimizing the selection of fracturing and treatment fluids to enhance recovery rate and minimize environmental risk.

Wettability of Mississippian Barnett Shale samples at different depths: Investigations from directional spontaneous imbibition

Because of its significant impact on relative permeability, capillary pressure, stimulation methods, and ultimate recovery, the wettability of reservoir rocks is a critical factor of the petroleum recovery process. However, characterizing the wettability of shale with extremely low matrix permeabilities is a challenging task because of the dominant presence of nanopores in shale and high heterogeneity of shale compositions at multiple scales. From spontaneous imbibition behavior that uses two types of imbibing fluid (water and n-decane), the present study examines the wettability characteristics of gas-window Barnett Shale samples taken from four different depths of Texas United 1 Blakely core in Wise County in Texas. Imbibition experiments were conducted in two directions: parallel and transverse to the lamination of the samples. A scaling method was used to analyze imbibition data, and observed imbibition behaviors were interpreted to infer the different wettability conditions of four samples with different mineralogy, total organic carbon content, and pore-throat size distribution. Our results show that wettability significantly affects fluid imbibition behavior and that four tested samples can be divided into three wettability categories: more water wet, mixed wet, and more oil wet. Overall, the variable wettability of Barnett samples will affect hydrocarbon storage, distribution, and production.

Modified seawater as a smart EOR fluid in chalk

Abstract Water based EOR by wettability alteration is of interest among the oil companies because of economic and environmental reasons. It is well known that seawater acts as a wettability modifier in carbonate reservoirs, and the seawater can even be improved as a smart EOR fluid by removing Na + and Cl − ions, and spiking this NaCl-depleted seawater with SO 4 2 - ions. In this paper we have addressed the degree of seawater modification needed to achieve reasonable improvements in oil recovery in spontaneous imbibition processes at 90 °C. Compared to ordinary seawater as imbibing fluid, more than 90% of the NaCl content must be removed in order to increase the oil recovery by 7–8% OOIP. Furthermore, compared to seawater depleted in NaCl, the oil recovery could be increased by 10% OOIP by spiking the NaCl depleted seawater with sulfate, 3–4 times the sulfate concentration present in seawater. The increased efficiency of modified seawater as a smart EOR fluid in carbonate is discussed in terms of a decrease in the ionic density of the double layer close to the positively charged calcite surface.

Gel Dehydration by Spontaneous Imbibition of Brine From Aged Polymer Gel

Summary This work investigates dehydration of polymer gel by capillary imbibition of water bound in gel into a strongly water-wet matrix. Polymer gel is a crosslinked-polymer solution of high water content, where water can leave the gel and propagate through porous media, whereas the large 3D polymer-gel structures cannot. In fractured reservoirs, polymer gel can be used for conformance control by reducing fracture conductivity. Dehydration of polymer gel by spontaneous imbibition (SI) contributes to shrinkage of the gel, which may open parts of the initially gel-filled fracture to flow and significantly reduce the pressure resistance of the gel treatment. SI of water bound in aged Cr(III)-acetate-hydrolized-polyacrcylamide (HPAM) gel was observed and quantified. Oil-saturated chalk-core plugs were submerged in gel, and the rate of SI was measured. Two boundary conditions were tested: all faces open (AFO) and two-end-open oil-water (TEO-OW), where one end was in contact with the imbibing fluid (gel or brine) and the other was in contact with oil. The rate of SI was significantly slower in gel compared with brine, and was highly sensitive to the ratio of matrix volume to surface open to flow, decreasing with increasing ratios. The presence of a dehydrated gel layer on the core surface lowered the rate of imbibition; continuous loss of water to the core increased the gel layer concentration and thus the barrier to flow between the core and fresh gel. Severe gel dehydration and shrinkage up to 99% were observed in the experiments, suggesting that gel treatments may lose efficiency over time in field applications where a potential for SI exists. The implications of gel dehydration by SI, and its relevance in field applications, are discussed for both gel and gelant field treatments.

Imbibition of concentrated suspensions in capillaries

We observe the imbibition of concentrated suspensions of rigid spherical particles into capillary tubes. We find that while the meniscus position advances according to the square root of time, the pre-factor of this “diffusive” scaling is smaller than that predicted by an ad-hoc extension of classical imbibition using an effective viscosity for the imbibing fluid. The reduction in the pre-factor is traced to the presence of axial variations in particle volume fraction, which arise as a result of shear-induced migration of particles across streamlines. In addition, we develop a model that accounts for the effect of both radial and axial variations in particle volume fraction on the movement of the imbibition front which partially accounts for the main experimental observations.

Scaling spontaneous imbibition of water data accounting for fluid viscosities

Spontaneous imbibition (SI) of water into the matrix blocks is regarded as a very important driving mechanism for oil recovery in dual porosity media. Oil recovery from such reservoirs is usually determined by mass transfer function between matrix and fracture. A new dimensionless scaling group has been developed which is able to correctly account for variation in fluid viscosities (imbibing fluid viscosity larger than initial fluid viscosity) when scaling spontaneous imbibition data generated by numerical simulation. The new dimensionless time is clearly superior to the usual scaling group established by Ma et al. (1997) when correlating the spontaneous imbibition data.

Wettability Alteration in Carbonates: The Effect of Water-Soluble Carboxylic Acids in Crude Oil

Acidic components in crude oil influence the wetting condition through their effect on electrostatic interactions with the mineral surfaces. In this paper, we have extracted water-soluble acids from a crude oil with a high acid number (AN) to study the effect of these acidic materials on the wetting condition. The AN for the original oil was 1.8 mg of KOH/g, while the AN for the oil depleted in water-soluble acids was 1.5 mg of KOH/g. Two crude oils have been studied by a chromatographic wettability test and spontaneous imbibition using seawater as imbibing fluid to determine the differences in the wetting condition and oil recovery. In a spontaneous imbibition process at 110 °C, both the imbibition rate and ultimate recovery were higher in the cores saturated with the oil depleted in water-soluble acids. The difference in the imbibition rate and also ultimate recovery indicates that the carboxylic material from the oil depleted in water-soluble acids can be displaced easily compared to the original oil. ...

“Smart Water” as a Wettability Modifier in Chalk: The Effect of Salinity and Ionic Composition

Seawater can improve the water wetness of chalk at high temperatures, which improves the oil displacement by spontaneous imbibition of water. It is experimentally verified that the interaction between Ca2+, Mg2+, and SO42− at the chalk surface will displace adsorbed carboxylic acids and increase the water wetness. In this work, the effect of salinity and ionic composition of smart water on oil recovery was studied at different temperatures, 100, 110, and 120 °C. The ultimate oil recovery was compared using seawater as the base fluid. When NaCl was removed from seawater, both the imbibition rate and oil recovery increased in comparison to seawater at the temperatures tested. At 110 and 120 °C, the oil recovery from seawater depleted in NaCl increased by about 10% of original oil in place (OOIP) compared to seawater. A decrease in oil recovery of about 5% of OOIP was observed when increasing the amount of NaCl in seawater 4 times. A systematic decrease in oil recovery was observed when using seawater diluted with distilled water as imbibing fluid. Imbibition tests at 110 °C showed that the water-wet fraction increased 29% for seawater depleted in NaCl compared to 11% for ordinary seawater. Diluted seawater to 10 000 ppm did not change wetting conditions at 110 °C. The results confirmed that not only is the concentration of the active ions Ca2+, Mg2+, and SO42− important for wettability alteration to take place but also the amount of non-active salt, such as NaCl, has an impact on the wettability alteration process, which is discussed as a double-layer effect at the chalk surface. No significant improvement in the ultimate oil recovery was observed during forced displacement by modified seawater.

Experimental study of spontaneous capillary imbibition in selected carbonate core samples

Spontaneous imbibition is of critical importance to oil recovery from fractured reservoirs. Scaling the core test data of spontaneous capillary imbibition with different imbibing fluids is crucial to properly design improved recovery methods and to predict their performances. This paper presents the results of static imbibition tests performed on cylindrical core samples taken from three wells completed in a fractured carbonate oil-wet reservoir located in the UAE. All experiments were conducted at ambient temperature with all faces of the cores open to free imbibition. Core samples were initially saturated with reservoir oil of 3.81 cp viscosity. A synthetic formation brine of 50,000 ppm NaCl concentration was used as the base imbibing phase. The effects of core permeability and the interfacial tension (IFT) of two chemical solutions on the rate of imbibitions and ultimate oil recovery were investigated. Also, the imbibition curves for the two chemical solutions (imbibing fluids) were used for scaling the imbibition data obtained from these experiments. The results of this work show that the core samples of this particular carbonate rock did not respond whatsoever to spontaneous imbibition with brine water, which is indicative of their strong wettability to oil. The ultimate oil recovery by free imbibition from these oil-wet core samples have been found to increase as the IFT is decreased and the core permeability is increased. The maximum observed ultimate oil recoveries are 16.24% and 4.83% of the original oil in place (OOIP) when a nonionic surfactant solution and alkali solution were used as the imbibing fluid, respectively. It is postulated that the nonionic surfactant can remove the adsorbed organic material from the solid surface which can lead to preferentially water-wet or intermediate wettability and an increase in oil relative permeability. Gravitational forces can then pull the oil out of the matrix because of lower capillarity and increased oil relative permeability. Finally, the application of the scaling group proposed by Li and Horne gave satisfactory correlation of all the imbibition data observed in this study.

Oil recovery from polar components (asphaltene and SA) treated chalk rocks by low salinity water and water containing SO 42− and Mg 2+ at different temperatures

Potential enhanced oil recovery by imbibing distilled water (DW expressed as low salinity water) into modified chalk is discussed in this paper. Average recovery of about 80% is estimated at different temperatures, 50, 70 and 90 °C for cores treated with asphaltene and stearic acid (SA). A synergistic effect between asphaltene and SA for alteration of chalk to more oil wet is also demonstrated. Aging time of 2 weeks for the used system is shown to be sufficient for imbibition experiments, where about 2.4% difference in oil recovery between the aged cores for 2 weeks and 6 months is observed. Presence of SO 4 2− in DW is shown to be more effective than that for DW in imbibition experiments at temperatures up to 50 °C. The recovery rate with low salinity water is shown to be higher, reaching the maximum recovery potential earlier than that with SO 4 2− as imbibing fluid. It is interesting to see that a large reduction in the potential oil recovery is observed when DW contains Mg 2+ is used as an imbibing fluid for cores treated with asphaltene. This is perhaps due to a molecular interlock phenomenon that enhances oil trapping.